Depletion Performance of Gas-Condensate Reservoirs

Abstract

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Introduction This paper reviews basic methods for evaluating the depletion performance of a well producing a gas-condensate fluid. In particular, we discuss initial gas-in-place estimates, inflow-performance relationships, the development and behavior of liquid saturations over both time and drainage area, and the interpretation of pressure-transient tests. Every aspect of these calculations for depletion of a gas-condensate, or any other essentially two-phase system, is implicitly dictated by the interaction between the fluid properties of the initial gas-in-place and the relative permeability properties of the reservoir rock. The simple steady-state theory forms a useful framework for understanding these interactions and often yields practical approximations for some important quantities. This theory and its relationship to commonly available laboratory measurements form the foundation for many of the methods discussed. Fluid Determination, Properties, and Descriptions Classification of a reservoir fluid as a black oil, volatile oil, gas condensate, wet gas, or dry gas is important because application of appropriate engineering practices to predict reserves and rates traditionally requires this knowledge. Fig. 1 is a schematic of a pressure/temperature (p-T) diagram for a multicomponent hydrocarbon mixture of constant composition. The region inside the envelope formed by the bubblepoint curve, critical point (C), and dewpoint curve is where liquid and vapor exist in equilibrium. Lines of constant liquid volume are shown inside this region. Fluids initially at temperature and pressure Positions I through V would be classified as a black oil, volatile oil, gas condensate, wet gas, and dry gas, respectively. Gas condensates are separated from the other fluid types by two characteristics: the condensation of a liquid phase at reservoir conditions during isothermal depletion and the retrograde (revaporization) nature of this condensation. Retrograde behavior of the condensing liquid phase can be seen by tracing the change in liquid volume along the constant-temperature line beginning at Point M in Fig. 1. After crossing the dewpoint line, the volume of liquid increases to approximately 10%at Point N and then begins to decrease with continued reduction in pressure.