Depletion Performance of Gas-Condensate Reservoirs
- Rajagopal Raghavan (Phillips Petroleum Co.) | Jack R. Jones (Amoco Production Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- August 1996
- Document Type
- Journal Paper
- 725 - 731
- 1996. Society of Petroleum Engineers
- 4.3.3 Aspaltenes, 5.4.2 Gas Injection Methods, 5.5 Reservoir Simulation, 5.6.8 Well Performance Monitoring, Inflow Performance, 4.3.4 Scale, 5.6.3 Pressure Transient Testing, 5.2.1 Phase Behavior and PVT Measurements, 5.8.8 Gas-condensate reservoirs, 5.6.9 Production Forecasting, 5.6.4 Drillstem/Well Testing, 5.2 Reservoir Fluid Dynamics, 2.4.3 Sand/Solids Control, 5.3.2 Multiphase Flow, 5.2.2 Fluid Modeling, Equations of State, 4.6 Natural Gas, 3.3 Well & Reservoir Surveillance and Monitoring
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Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area,these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleumengineering.
This paper reviews basic methods for evaluating the depletion performance ofa well producing a gas-condensate fluid. In particular, we discuss initialgas-in-place estimates, inflow-performance relationships, the development andbehavior of liquid saturations over both time and drainage area, and theinterpretation of pressure-transient tests. Every aspect of these calculationsfor depletion of a gas-condensate, or any other essentially two-phase system,is implicitly dictated by the interaction between the fluid properties of theinitial gas-in-place and the relative permeability properties of the reservoirrock. The simple steady-state theory forms a useful framework for understandingthese interactions and often yields practical approximations for some importantquantities. This theory and its relationship to commonly available laboratorymeasurements 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, gascondensate, wet gas, or dry gas is important because application of appropriateengineering practices to predict reserves and rates traditionally requires thisknowledge. Fig. 1 is a schematic of a pressure/temperature (p-T) diagram for amulticomponent hydrocarbon mixture of constant composition. The region insidethe envelope formed by the bubblepoint curve, critical point (C), and dewpointcurve is where liquid and vapor exist in equilibrium. Lines of constant liquidvolume are shown inside this region. Fluids initially at temperature andpressure Positions I through V would be classified as a black oil, volatileoil, gas condensate, wet gas, and dry gas, respectively. Gas condensates areseparated from the other fluid types by two characteristics: the condensationof a liquid phase at reservoir conditions during isothermal depletion and theretrograde (revaporization) nature of this condensation. Retrograde behavior ofthe condensing liquid phase can be seen by tracing the change in liquid volumealong the constant-temperature line beginning at Point M in Fig. 1. Aftercrossing the dewpoint line, the volume of liquid increases to approximately 10%at Point N and then begins to decrease with continued reduction inpressure.
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