Oil reservoir fluids are mainly complex mixtures of the hydrocarbon compounds, which frequently contain impurities such as nitrogen, carbon dioxide, and hydrogen sulfide. The composition in mole percentages of several typical reservoir liquids is given in Table 6.1, together with the tank gravity of the crude oil, the gas-oil ratio of the reservoir mixture, and other characteristics of the fluids.1 The composition of the tank oils obtained from the reservoir fluids are quite different from the composition of the reservoir fluids, owing mainly to the release of most of the methane and ethane from solution and the vaporization of sizeable fractions of the propane, butanes, and pentanes, as pressure is reduced in passing from the reservoir to the stock tank. The table shows a good correlation between the gas-oil ratios of the fluids and the percentages of methane and ethane they contain over a range of gas-oil ratios, from only 22 SCF/STB up to 4053 SCF/STB.
Table 6.1 Reservoir Fluid Compositions and Properties (after Kennerly, Courtesy Core Laboratories, Inc.)1
Several methods are available for collecting samples of reservoir fluids. The samples may be taken with subsurface sampling equipment lowered into the well on a wire line, or samples of the gas and oil may be collected at the surface and later recombined in proportion to the gas-oil ratio measured at the time of sampling. Samples should be obtained as early as possible in the life of the reservoir, preferably at the completion of the discovery well, so that the sample approaches as nearly as possible the original reservoir fluid. The type of fluid collected in a sampler is dependent on the well history prior to sampling. Unless the well has been properly conditioned before sampling, it is impossible to collect representative samples of the reservoir fluid. A complete well-conditioning procedure has been described by Kennedy and Reudelhuber.1,2 The information obtained from the usual fluid sample analysis includes the following properties:
1. Solution and evolved gas-oil ratios and liquid phase volumes
2. Formation volume factors, tank oil gravities, and separator and stock-tank gas-oil ratios for various separator pressures
3. Bubble-point pressure of the reservoir fluid
4. Compressibility of the saturated reservoir oil
5. Viscosity of the reservoir oil as a function of pressure
6. Fractional analysis of a casing head gas sample and of the saturated reservoir fluid
If laboratory data are not available, satisfactory estimations for a preliminary analysis can often be made from empirical correlations, like those considered that is based on data usually available. These data include the gravity of the tank oil, the specific gravity of the produced gas, the initial producing gas-oil ratio, the viscosity of the tank oil, the reservoir temperature, and the initial reservoir pressure.
In most reservoirs, the variations in the reservoir fluid properties among samples taken from different portions of the reservoir are not large, and they lie within the variations inherent in the techniques of fluid sampling and analysis. In some reservoirs, on the other hand, particularly those with large closures, there are large variations in the fluid properties. For example, in the Elk Basin Field, Wyoming and Montana, under initial reservoir conditions, there was 490 SCF of gas in solution per barrel of oil in a sample taken near the crest of the structure but only 134 SCF/STB in a sample taken on the flanks of the field, 1762 ft lower in elevation.3 This is a solution gas gradient of 20 SCF/STB per 100 ft of elevation. Because the quantity of solution gas has a large effect on the other fluid properties, large variations also occur in the fluid viscosity, the formation volume factor, and the like. Similar variations have been reported for the Weber sandstone reservoir of the Rangely Field, Colorado, and the Scurry Reef Field, Texas, where the solution gas gradients were 25 and 46 SCF/STB per 100 ft of elevation, respectively.4,5 These variations in fluid properties may be explained by a combination of (1) temperature gradients, (2) gravitational segregation, and (3) lack of equilibrium between the oil and the solution gas. Cook, Spencer, Bobrowski, and Chin, and McCord have presented methods for handling calculations when there are significant variations in the fluid properties.5,6
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