One of the major disadvantages associated with the use of lean gas in gas-cycling applications is that the income that would be derived from the sale of the lean gas is deferred for several years. For this reason, the use of nitrogen has been suggested as a replacement for the lean gas.16 However, one might expect the phase behavior of nitrogen and a wet gas to exhibit different characteristics from that of lean gas and the same wet gas. Researchers have found that mixing nitrogen and a typical wet gas causes the dew point of the resulting mixture to be higher than the dew point of the original wet gas.17,18 This is also true for lean gas, but the dew point is raised higher with nitrogen.17 If, in a reservoir situation, the reservoir pressure is not maintained higher than this new dew point, then retrograde condensation will occur. This condensation may be as much or more than what would occur if the reservoir was not cycled with gas. Studies have shown, however, that very little mixing occurs between an injected gas and the reservoir gas in the reservoir.17,18 Mixing occurs as a result of molecular diffusion and dispersion forces, and the resulting mixing zone width is usually only a few feet.19,20 The dew point may be raised in this local area of mixing, but this will be a very small volume and, as a result, only a small amount of condensate may drop out. Vogel and Yarborough have also shown that, under certain conditions, nitrogen revaporizes the condensate.18 The conclusion from these studies indicates that nitrogen can be used as a replacement for lean gas in cycling operations with the potential for some condensate formation that should be minimal in most applications.
Kleinsteiber, Wendschlag, and Calvin conducted a study to determine the optimum plan of depletion for the Anschutz Ranch East Unit, which is located in Summit County, Utah, and Uinta County, Wyoming.21 The Anschutz Ranch East Field, discovered in 1979, is one of the largest hydrocarbon accumulations found in the Western Overthrust Belt. Tests have indicated that the original in-place hydrocarbon content was over 800 million bbl of oil equivalent. Laboratory experiments conducted on several surface-recombined samples indicated that the reservoir fluid was a rich gas condensate. The fluid had a dew point only 150 to 300 psia below the original reservoir pressure of 5310 psia. The dew-point pressure was a function of the structural position in the reservoir, with fluid near the water-oil contact having a dew point about 300 psia lower than the original pressure and field near the crest having a dew point only about 150 psia lower. The liquid saturation, observed in constant composition expansion tests, accumulated very rapidly below the dew point, suggesting that depletion of the reservoir and the subsequent drop in reservoir pressure could cause the loss of significant amounts of condensate. Because of this potential lxxxxxoss of valuable hydrocarbons, a project was undertaken to determine the optimum method of production.21
To begin the study, a modified Redlich-Kwong equation of state was calibrated with the laboratory phase behavior data that had been obtained.17,22 The equation of state was then used in a compositional reservoir simulator. Several depletion schemes were considered, including primary depletion and partial or full pressure maintenance. Wet hydrocarbon gas, dry hydrocarbon gas, carbon dioxide, combustion flue gas, and nitrogen were all considered as potential gases to inject. Carbon dioxide and flue gas were eliminated due to lack of availability and high cost. The results of the study led to the conclusion that full pressure maintenance should be used. Liquid recoveries were found to be better with dry hydrocarbon gas than with nitrogen. However, when nitrogen injection was preceded by a 10% to 20% buffer of dry hydrocarbon gas, the liquid recoveries were nearly the same. When an economic analysis was coupled with the simulation study, the decision was to conduct a full-pressure maintenance program with nitrogen as the injected gas. A 10% pore volume buffer, consisting of 35% nitrogen and 65% wet hydrocarbon gas, was to be injected before the nitrogen to improve the recovery of liquid condensate.
The approach taken in the study by Kleinsteiber, Wendschlag, and Calvin would be appropriate for the evaluation of any gas-condensate reservoir. The conclusions regarding which injected material is best or whether a buffer would be necessary may be different for a reservoir gas of different composition
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