Translation of Chapter 25 of the Book of Charles E. Webber – Manual of Petroleum Exploration.
Natural gas liquids are defined in the annual reports of the American Gas Association, American Petroleum Institute, Petroleum Association of Canada as “those hydrocarbon liquids that are gaseous or in solution with crude oil in the reservoir and are recoverable as liquids by condensation or absorption process taking place in field separators, scrubbers, gas plants or cycling plants. The natural gas, condensate and liquefied petroleum gases are considered in this category.
Natural gas production can yield two widespread but closely related types of liquid gas. The first type of liquid is one which is not separated from the gas passing through the separator regular field but which must be recovered by cooling, compression, or stripping in a natural gas processing plant. Thus, these gas liquids obtained are normally expected as natural gas and liquefied petroleum gas. The other gas liquids separated by choice (retrograde condensation) is going through the regular separator where the pressure and temperature are naturally low during the course of production. This type of liquid, called gas-condensate is heavier than natural gas and resembles a very volatile crude oil may vary in color from water white to amber. The gases that yield a high volume of liquid, so it is natural gas and liquefied petroleum gas or condensate, is called “gas rich” or “heavy.” The gas yields yields little or no liquid of any kind is referred to as “clean” or “dry.”
During the early stages of field development, estimated reserves of natural gas liquids of the first type are still those that include natural gas and liquefied petroleum gas, are not normally made. However, sometimes a rich gas will obviously be best process for recovery of natural gas and liquefied petroleum gas. In such cases the liquid gas content is determined by calculating the volume of propane, butane, pentane and heavier hydrocarbons from natural gas analysis. This calculation is very simple and simply means the sum of the quotients obtained by dividing the percentage by mass or volume for each of the components of the gas (propane, butane, etc.) according to factor cubic feet of vapor per gallon of liquid ” (GSFA, 1957) for that particular component which is often done in the laboratory. Example:
Most times, the production volume exceeds the volume of water existing invaded therefore the reservoir pressure will fall during the life of production and liquids will condense in the pore spaces of the reservoir, some of which remain forever. In these reservoirs the recovery factor will be less than the recovery factor for gas. As a broad general statement, the magnitude of these losses of fluids due to retrograde condensation in the reservoir is dependent upon the initial ratio gas / liquid and the anticipated reduction in the low pressure drop.
Figure 25.4 shows the condensate recovery factors Rc ratio as a function of gas / condensate and pressure drop. These data are calculated by a procedure outlined by Brinkley and Curtis (1951).