Introduction

The contains a discussion of single-phase gas reservoirs (refer to Fig. 1.4). In a single-phase gas reservoir, the reservoir fluid, usually called natural gas, remains as nonassociated gas during the entire producing life of the reservoir. This type of reservoir is frequently referred to as a dry gas reservoir because no condensate is formed in the reservoir during the life of production. However, many of these wells do produce condensate, because the temperature and pressure conditions in the producing well and at the surface can be significantly different from the reservoir temperature and pressure. This change in conditions can cause some components in the producing gas phase to condense and be produced as liquid. The amount of condensation is a function of not only the pressure and temperature but also the composition of the natural gas, which typically consists primarily of methane and ethane. The tendency for condensate to form on the surface increases as the concentration of heavier components increases in the reservoir fluid.

In beginning any type of reservoir analysis, specific information about the reservoir must be obtained in order to estimate the total hydrocarbon in place in the reservoir. As this chapter focuses exclusively on gas, this analysis will be presented by way of calculating a total gas in place. Typically, the reservoir formation will be mapped by seismic data that will allow for the determination of the areal extent of the reservoir (the total acreage of the underground formation) and also the reservoir thickness. These values are then multiplied together to determine the initial bulk volume of the reservoir. Core samples taken from appraisal wells will establish porosity and the relative fractions of oil, gas, and water. These are typically denoted S_o for oil, S_g for gas, and S_w for water. The letter i, when added to the subscript, denotes the initial value of that fraction.

A second crucial piece of information to be determined before commercial production begins is the estimated unit recovery. This unit recovery is the difference between the initial gas in place and the gas remaining in the reservoir at the time of abandonment and represents the total gas that can be produced from the reservoir. This same information is often expressed as a recovery factor, showing the percent of the initial gas in place that can be produced. These pieces of information are crucial for making the economic decision behind the development of a hydrocarbon reservoir.

The recovery factor itself is dependent on the production mechanism for the reservoir. Two main mechanisms in gas reservoirs will be discussed. They are gas drive, which is the expansion of the gas in the reservoir due to a drop in reservoir pressure as gas is being produced, and water drive, which is the encroachment of water in the reservoir due to contact with an aquifer. In the case of a gas drive, there is neither water encroachment into nor water production from the reservoir of interest, and the reservoir is said to be volumetric. They will also provide a description of two methods that are used to determine the initial gas in place. The first of these methods uses geological, geophysical, and fluid property data to estimate volumes of gas. The second method uses the material balance equation derived.