Deliverability of Gas-Condensate Reservoirs — Field Experiences and Prediction Techniques

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 Predicting and assuring well deliverability often are important concerns when developing gas-condensate reservoirs. Many gas-condensate projects are in deep, hot, low-permeability reservoirs for which well costs are a significant part of the project economics. It is well known that the deliverability of gas-condensate wells can be impaired by the formation of a condensate bank once the bottomhole pressure drops below the dewpoint. This paper outlines the five steps—appropriate laboratory measurements, fitting laboratory data to relative permeability models, use of spreadsheet tools, single-well models, full-field models (FFMs)—to predict deliverability loss caused by condensate banking. It then discusses integrated laboratory/simulation field studies used to validate these steps. Finally, options to improve well deliverability are explored. Gas Condensate and Banking Typically, gas-condensate reservoirs are single-phase gas in the reservoir at discovery, but yield small amounts of oil at the surface (approximately 10 to 300 STB/MMscf). They have a composition consisting largely of methane and small fractions of intermediate and heavy ends (typically, approximately 87% C1, 9% C2-6, and 4% C7+). The temperatures encountered in these reservoirs (200 to 400°F) are higher than the critical temperature of the fluid, but lower than the maximum temperature extent of its two-phase region. As Fig. 1 shows, the gas is extracted, the pressure declines isothermally, and at the dewpoint, the first droplets of liquid formed from the heavier hydrocarbon components appear. A gas-condensate system is also characterized by a liquid-condensation curve such as that shown in Fig. 2. A lean system may have a yield of approximately 10 STB/MMscf (2% maximum condensate), and a rich system could yield as much as 300 STB/MMscf (20% condensate). When the flowing bottomhole pressure falls below the dewpoint of the reservoir fluid, liquid condensate builds up (condensate banking) near the wellbore, as shown in Fig. 3.