The five reservoir fluids (black oils, volatile oils, retrograde gas-condensates, wet gases, and dry gases) are defined because production of each fluid requires different engineering techniques. The fluid type must be determined very early in the life of a reservoir (often before sampling or initial production) because fluid type is the critical factor in many of the decisions that must be made about producing the fluid from the reservoir.
Reservoir fluid type can be confirmed only by observing a representative fluid sample in the laboratory. However, "rules of thumb" based on initial producing GOR, stock-tank liquid gravity, and stock-tank liquid color usually will indicate fluid type. Initial producing GOR is the most important of these indicators; nevertheless, both stock-tank liquid gravity and color are useful in validating the fluid type inferred from the GOR. Darker colors are associated with the largest, heaviest molecules in the petroleum mixtures.
Black oils are mixtures of thousands of different chemical species ranging from methane to large, heavy, virtually nonvolatile molecules. Volatile oils contain fewer of the heavier molecules. Retrograde gases have even fewer of the heavy ends, wet gases still fewer, and dry gases are essentially pure methane. These differences in composition cause the five fluids to have different phase diagrams, which cause differences in behavior in the reservoir and at surface conditions.
The heavy components in the petroleum mixtures have the strongest effect on fluid characteristics. Normally, laboratory tests combine the heavy components as a "heptanes-plus" fraction. Fig. 1 illustrates the effect of this heavy fraction on the most important of the fluid-type indicators: the initial producing GOR. Black oils, represented at the lower right end of the graph, have the lowest initial GOR's and the highest concentrations of heavy components. Dry gases are located at the upper left of the graph. The other fluids exist in a continuum between these two. The GOR's in Fig. 1 are not normalized to any standard surface facilities or standard operating conditions; nonetheless, the graph is an aid in understanding the differences among the five fluids.
Black oils and volatile oils both are liquids in the reservoir, both exhibit bubblepoints as reservoir pressure is decreased during production, and both release gas in the reservoir pore space at pressures below the bubblepoint. However, there is a good reason for classifying them separately. The "oil material-balance equations," which are used for black oils, will give incorrect results for volatile oils; the behavior of volatile oils does not fit the assumptions inherent in derivation of these equations.
The gas that comes out of solution in the reservoir from a black oil below its bubblepoint is usually a dry gas. As this free gas is produced, it remains a gas as pressure and temperature are reduced to separator conditions. As reservoir pressure decreases, the gas leaving solution becomes richer in intermediate components, and the gas could become a wet gas. However, this occurs late in the life of the reservoir and has little effect on ultimate production.
The gas that comes out of solution in the reservoir from a volatile oil is normally a retrograde gas. This free gas will exhibit retrograde behavior in the reservoir and when produced will release a large amount of condensate at surface conditions. The quantity of condensate released from the free gas associated with a volatile oil is significant; often more than one-half the stock-tank liquid produced during the life of a volatile oil reservoir left the reservoir as free gas.
Thus, the important difference between black oils and volatile oils is that the solution gases from black oils remain solely in the gas phase as they move through the reservoir, the tubulars, and the separator; the solution gases from volatile oils are rich and lose condensate in the separator. One assumption inherent in the derivation of classic material-balance equations is that the free gas in the reservoir remains as gas through the separator.
The material-balance equations treat a multicomponent black-oil mixture as a two-component mixture: gas and oil. Reservoir engineering calculations for volatile oils must treat the mixture as a multicomponent mixture so that the total composition of the production stream is known and separator calculations (which require knowledge of composition) can be performed to determine the amounts of liquid and gas at the surface.
Special laboratory procedures can predict the recovery of volatile oils under depletion drive; however, these are somewhat difficult to analyze. Above the bubblepoint, the undersaturated-black-oil material-balance equation can be used for volatile oils. Below the bubblepoint, compositional material-balance calculations normally are required, either with K factors or equations-of-state (EOS). The special laboratory procedures mentioned above help in deriving the K factors or "tuning" the EOS.
Examination of hundreds of laboratory studies indicates that one should suspect the presence of a volatile oil whenever the initial producing GOR exceeds about 1,750 scf/STB, especially if the stock-tank oil gravity is high. Another indicator of volatile oil is a stock-tank oil gravity exceeding 40 API with some color: brown, reddish, orange, even green. If the oil FVF at the bubblepoint is measured in the laboratory, a value of 2.0 RB/STB or greater is expected for a volatile oil.
The data in Fig. 2 (a subset of the data in Fig. 1) illustrate the differences in composition between volatile oils and black oils.
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