This chapter is from the book
This chapter is from the book
This chapter is from the book
1.3 Introduction to Terminology
The purpose of this section is to provide an explanation to the reader of the terminology that will be used throughout the book by providing context for the terms and explaining the interaction of the terms. Before defining these terms, note Fig. 1.2, which illustrates a cross section of a producing petroleum reservoir.
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Figure 1.2 Diagram to show the occurrence of petroleum under the Earth’s surface.
A reservoir is not an open underground cavern full of oil and gas. Rather, it is section of porous rock (beneath an impervious layer of rock) that has collected high concentrations of oil and gas in the minute void spaces that weave through the rock. That oil and gas, along with some water, are trapped beneath the impervious rock. The term porosity (φ) is a measure, expressed in percent, of the void space in the rock that is filled with the reservoir fluid.
Reservoir fluids are segregated into phases according to the density of the fluid. Oil specific gravity (γo) is the ratio of the density of oil to the density of water, and gas specific gravity (γg) is the ratio of the density of natural gas to the density of air. As the density of gas is less than that of oil and both are less than water, gas rests at the top of the reservoir, followed by oil and finally water. Usually the interface between two reservoir fluid phases is horizontal and is called a contact. Between gas and oil is a gas-oil contact, between oil and water is an oil-water contact, and between gas and water is a gas-water contact if no oil phase is present. A small volume of water called connate (or interstitial) water remains in the oil and gas zones of the reservoir.
The initial amount of fluid in a reservoir is extremely important. In practice, the symbol N (coming from the Greek word naptha) represents the initial volume of oil in the reservoir expressed as a standard surface volume, such as the stock-tank barrel (STB). G and W are initial reservoir gas and water, respectively. As these fluids are produced, the subscript p is added to indicate the cumulative oil (Np), gas (Gp), or water (Wp) produced.
The total reservoir volume is fixed and dependent on the rock formations of the area. As reservoir fluid is produced and the reservoir pressure drops, both the rock and the fluid remaining in the reservoir expand. If 10% of the fluid is produced, the remaining 90% in the reservoir must expand to fill the entire reservoir void space. When the hydrocarbon reservoir is in contact with an aquifer, both the hydrocarbon fluids and the water in the aquifer expand as hydrocarbons are produced, and water entering the hydrocarbon space can replace the volume of produced hydrocarbons.
To account for all the reservoir fluid as pressure changes, a volume factor (B) is used. The volume factor is a ratio of the volume of the fluid at reservoir conditions to its volume at atmospheric conditions (usually 60°F and 14.7 psi). Oil volume at these atmospheric conditions is measured in STBs (one barrel is equal to 42 gallons). Produced gases are measured in standard cubic feet (SCF). An M (1000) or MM (1 million) or MMM (1 billion) is frequently placed before the units SCF. As long as only liquid phases are in the reservoir, the oil and water volume factors (Bo and Bw) will begin at the initial oil volume factors (Boi and Bwi) and then steadily increase very slightly (by 1%–5%). Once the saturation pressure is reached and gas starts evolving from solution, the oil volume factor will decrease. Gas (Bg) volume factors will increase considerably (10-fold or more) as the reservoir pressure drops. The change in volume factor for a measured change in the reservoir pressure allows for simple estimation of the initial gas or oil volume.
When the well fluid reaches the surface, it is separated into gas and oil. Figure 1.3 shows a two-stage separation system with a primary separator and a stock tank. The well fluid is introduced into the primary separator where most of the produced gas is obtained. The liquid from the primary separator is then flashed into the stock tank. The liquid accumulated in the stock tank is Np, and any gas from the stock tank is added to the primary gas to arrive at the total produced surface gas, Gp. At this point, the produced amounts of oil and gas are measured, samples are taken, and these data are used to evaluate and forecast the performance of the well.
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Figure 1.3 Schematic representation of produced well fluid and a surface separator system.