Testing of gas condensate reservoirs requires careful coordination of all parameters in the analytical process. Therefore, the sampling procedure, the laboratory analysis of the collected samples, the design of the testing equipment, and the design and analysis of the test itself are all critical to the accuracy of the analysis. This paper will outline the methodology and procedures used in testing gas condensate reservoirs.

Obtaining a representative formation fluid sample that may be used for compositional and pressure-volume-temperature (PVT) analysis is crucial in testing gas condensate reservoirs. In most cases, this means maintaining a monophasic sample as close as possible to actual reservoir conditions. New sampling technologies have been introduced that improve the quality of the initial sample and can maintain the sample integrity. Additionally, new downhole sensor technologies show promise of improving sample contamination estimates and making in-situ fluid property measurements. The various sampling techniques are discussed, and comparisons of processes that include wireline formation testing and bottomhole sampling, isokinetic sampling used in drillstem and production testing, and surface sampling are made.

Laboratory testing procedures including sample quality validation, error propagation, and sample contamination are also discussed.

The flow of gas condensate in a reservoir is a complicated mathematical problem involving phase changes, condensate loss into the small pores of the rock, multi-phase-flow of the wet gas oil and possibly water, phase redistribution in and around the wellbore, and finally, liquid vaporization back into the condensate gas. A well test can provide identification of the absolute reservoir and relative permeabilities, the source of declining gas permeability, near wellbore damage, and the reservoir pressure. It can also distinguish the extent of the liquid-condensate bank that forms a composite reservoir, as well as the location of the nearby boundaries.

The analysis procedure and techniques will be illustrated through presentation of two field cases. In the first case, the flowing pressure is above the dewpoint pressure. Thus, the fluid inside the reservoir is a single-phase gas, and liquid dropout causes phase segregation in the wellbore. In the second case, the well is producing below the dewpoint pressure while the original reservoir pressure is above the dewpoint pressure. This caused the well test to resemble that of a composite reservoir with earlier phase-segregation effects.

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