Page 18 - Standard Handbook Petroleum Natural Gas Engineering VOLUME2

Basic Principles, Definitions, and Data 7

suitable for computer use. In a later section, the use of such programs for
estimating PVT properties will be presented. In the initial sections, the presenta-
tion of graphical data will be instructive to gaining a better understanding of
the effect of certain variables.
Water

Regardless of whether a reservoir yields pipeline oil, water in the form
commonly referred to as interstitial or connate is present in the reservoir in
pores small enough to hold it by capillary forces.
The theory that this water was not displaced by the migration of oil into a
water-bearing horizon is generally accepted as explanation of its presence.
The amount of the interstitial water is usually inversely proportional to the
permeability of the reservoir. The interstitial water content of oil-producing
reservoirs often ranges from 10% to 40% of saturation.
Consideration of interstitial water content is of particular importance in
reservoir studies, in estimates of crude oil reserves and in interpretation of
electrical logs.
Fluid Viscosities

Gas Viscosity. Viscosities of natural gases are affected by pressure, temperature,
and composition. The viscosity of a specific natural gas can be measured in
the laboratory, but common practice is to use available empirical data such as
those shown in Figures 5-6 and 5-7. Additional data are given in the Handbook
of Natural Gas Engineering [3]. Contrary to the case for liquids, the viscosity of
a gas at low pressures increases as the temperature is raised. At high pressures,
gas viscosity decreases as the temperature is raised. At intermediate pressures,
gas viscosity may decrease as temperature is raised and then increase with
further increase in temperature.
Oil Viscosity. The viscosity of crude oil is affected by pressure, temperature,
and most importantly, by the amount of gas in solution. Figure 5-8 shows the
effect of pressure on viscosities of several crude oils at their respective reservoir
temperatures [4]. Below the bubble-point, viscosity decreases with increasing
pressure because of the thinning effect of gas going into solution. Above the
bubble-point, viscosity increases with increasing pressure because of compression
of the liquid. If a crude oil is undersaturated at the original reservoir pressure,
viscosity will decrease slightly as the reservoir pressure decreases. A minimum
viscosity will occur at the saturation pressure. At pressures below the bubble-
point, evolution of gas from solution will increase the density and viscosity of
the crude oil as the reservoir pressure is decreased further.
Viscosities of hydrocarbon liquids decrease with increasing temperature as
indicated in Figure 5-9 for gas-free reservoir crudes [5]. In cases where only the
API gravity of the stock tank oil and reservoir temperature are known, Figure
5-9 can be used to estimate dead oil viscosity at atmospheric pressure. However,
a more accurate answer can be obtained easily in the laboratory by simply
measuring viscosity of the dead oil with a viscometer at reservoir temperature.
With the dead oil viscosity at atmospheric pressure and reservoir temperature
(either measured or obtained from Figure 5-9), the effect of solution gas can
be estimated with the aid of Figure 5-10 [6]. The gas-free viscosity and solution
gas-oil ratio are entered to obtain viscosity of the gas-saturated crude at the
bubble-point pressure. This figure accounts for the decrease in viscosity caused