ESTIMATED RESERVES OF NATURAL GAS LIQUIDS

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:

The content of gasoline is 0,324 gallons per 100 cubic feet or 3.24 gallons per 1000 cubic feet or multiplying this value by the determined recoverable gas reserves of the formula (25-5) (25-6), or (25-7) gives the estimate of recoverable liquid gas. It is obvious that for this type of gas, where the liquid content is assumed constant, the recovery factor for LPG (natural gas and liquefied petroleum gas) must be the same as the recovery factor for gas.Condensed gas production may have an additional complication. If a good push for water efficiency, the gas will be produced with little or no pressure drop in the reservoir.

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. Recovery Factor vs. Rc barrels condensate. Initial production gas / condensate ratio.

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).

Gas-condensate is usually determined experimentally by measurement of accumulated liquid condensate which is produced with a gas volume measurement. This chart is the initial ratio of gas / condensate. In a field test drive large-scale flow of gas / condensate, it is important that the well to flow for a long time before testing to ensure that drilling fluids have been well cleaned and flow conditions stabilize. This usually takes a minimum of 24 hours for a reasonable stream radio quickly. The initial ratio of gas / condensate, multiplied by the estimated volume of natural gas in the reservoir that gives us the condensate in situ. The formula (25-7) would be applied for these calculations except for the recovery factor R shown for the gas would be replaced by the recovery factor Rc condensate Figure 25.4.

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