Introduction

Gas-condensate production may be thought of as intermediate between oil and gas. Oil reservoirs have a dissolved gas content in the range of zero (dead oil) to a few thousand cubic feet per barrel, whereas in gas reservoirs, 1 bbl of liquid (condensate) is vaporized in 100,000 SCF of gas or more, from which a small or negligible amount of hydrocarbon liquid is obtained in surface separators. Gas-condensate production is predominantly gas from which more or less liquid is condensed in the surface separators—hence the name gas condensate. The liquid is sometimes called by an older name, distillate, and also sometimes simply oil because it is an oil. Gas-condensate reservoirs may be approximately defined as those that produce light-colored or colorless stock-tank liquids with gravities above 45 °API at gas-oil ratios in the range of 5000 to 100,000 SCF/STB. Allen has pointed out the inadequacy of classifying wells and the reservoirs from which they produce entirely on the basis of surface gas-oil ratios—for the classification of reservoirs, as discussed properly depends on (1) the composition of the hydrocarbon accumulation and (2) the temperature and pressure of the accumulation in the Earth.¹

As the search for new fields led to deeper drilling, new discoveries consisted predominately of gas and gas-condensate reservoirs. Figure 5.1, based on well test data reported in Ira Rinehart’s Yearbooks, shows the discovery trend for 17 parishes in southwest Louisiana for 1952–56, inclusive.² The reservoirs were separated into oil and gas or gas-condensate types on the basis of well test gas-oil ratios and the API gravity of the produced liquid. Oil discoveries predominated at depths less than 8000 ft, but gas and gas-condensate discoveries predominated below 10,000 ft. The decline in discoveries below 12,000 ft was due to the fewer number of wells drilled below that depth rather than to a drop in the occurrence of hydrocarbons. Figure 5.2 shows the same data for the year 1955 with the gas-oil ratio plotted versus depth. The dashed line marked “oil” indicates the general trend to increased solution gas in oil with increasing pressure (depth), and the envelop to the lower right encloses those discoveries that were of the gas or gas-condensate types.

Figure 5.1 Discovery frequency of oil and gas or gas-condensate reservoirs versus depth for 17 parishes in southwest Louisiana, 1952–56, inclusive (data from Ira Rinehart’s Yearbooks).²

Figure 5.2 Plot showing trend of increase of gas-oil ratio versus depth for 17 parishes in southwest Louisiana during 1955 (data from Ira Rinehart’s Yearbooks).²

Muskat, Standing, Thornton, and Eilerts have discussed the properties and behavior of gas-condensate reservoirs.^3–6 Table 5.1, taken from Eilerts, shows the distribution of the gas-oil ratio and the API gravity among 172 gas and gas-condensate fields in Texas, Louisiana, and Mississippi.⁶ These authors found no correlation between the gas-oil ratio and the API gravity of the tank liquid for these fields.

Table 5.1 Range of Gas-Oil Ratios and Tank Oil Gravities for 172 Gas and Gas-Condensate Fields in Texas, Louisiana, and Mississippi

In a gas-condensate reservoir, the initial phase is gas, but typically the fluid of commercial interest is the gas condensate. The strategies for maximizing recovery of the condensate distinguish gas-condensate reservoirs from single-phase gas reservoirs. For example, in a single-phase gas reservoir, reducing the reservoir pressure increases the recovery factor, and a water drive is likely to reduce the recovery factor. In a gas-condensate reservoir, reducing the reservoir pressure below the dew-point pressure reduces condensate recovery, and therefore a water drive that maintains the reservoir pressure above the dew-point pressure will likely increase condensate recovery. Similarly, strategies for increasing condensate recovery differ from those used for oil recovery. In particular, injecting water maintains pressure and displaces oil toward producing wells, but for condensate, it is better to use gas as a pressure maintenance and displacement fluid. The will aid the engineer in designing a recovery plan for a gas-condensate reservoir that will attempt to maximize the production of the more valuable components of the reservoir fluid.