Condensate Bank Characterization from Well Test Data and Fluid PVT Properties

Abstract

Published well-test analyses in gas/condensate reservoirs in which the pressure has dropped below the dewpoint are usually based on a two-or three-region radial composite well-test interpretation model to represent condensate dropout around the wellbore and initial gas in place away from the well. Gas/condensate-specific results from well-test analysis are the mobility and storativity ratios between the regions and the condensate-bank radius. For a given region, however, well-test analysis cannot uncouple the storativity ratio from the region radius, and the storativity ratio must be estimated independently to obtain the correct bank radius. In most cases, the storativity ratio is calculated incorrectly, which explains why condensate bank radii from well-test analysis often differ greatly from those obtained by numerical compositional simulation.In this study, a new method is introduced to estimate the storativity ratios between the different zones from buildup data when the saturation profile does not change during the buildup. Application of the method is illustrated with the analysis of a transientpressure test in a gas/condensate field in the North Sea. The analysis uses single-phase pseudopressures and two-and three-zone radial composite well-test interpretation models to yield the condensate-bank radius. The calculated condensate-bank radius is validated by verifying analytical well-test analyses with compositional simulations that include capillary number and inertia effects. Fig. 1-Schematic of pressure and derivative composite behavior (Gringarten et al. 2000).

Volatile oil well test analysis: application of two-phase pseudo-pressure approach

“…The third method provides oil saturation for long duration tests. In this case, fluid composition varies with time, and the oil saturation around the wellbore is best evaluated from PVT properties of the produced fluid at production time (Bozorgzadeh and Gringarten 2006).…”

“…The flow behavior and well test interpretation of gas condensate systems by the above-mentioned methods have been widely discussed in the literature (Gringarten et al 2000(Gringarten et al , 2006Bozorgzadeh and Gringarten 2006;Xu and Lee 1999;Mazloom and Rashidi 2006;Yousefi et al 2014;Shahbazi et al 2016). However, limited publications deal with volatile oil reservoirs below the P b (Sharifi and Ahmadi 2009;Sanni and Gringarten 2008).…”

Integrated study of gas condensate reservoir characterization through pressure transient analysis

“…A novel approach was introduced in the use of twophase pseudo-pressure for the interpretation of gas condensate well test data in naturally fractured reservoirs (Mazloom et al, 2005). In addition, a method to characterize condensate bank was proposed by Bozorgzadeh et al (2006). A Fetkovich method was chosen to evaluate the reservoir productivity and the well future production performance in conjunction with well test analysis based on real drawdown test data (Zheng et al, 2006).…”

Wettability Alteration at Optimum Fluorinated Polymer Concentration for Improvement in Gas Mobility

“…Another approach has been proposed, altering wettability of the system to intermediate gas-wetting. This approach changes the contact angle instead of the interfacial tension and consequently, it increases the oil and gas relative permeability curves (Fulcher et al 1985) The mobility in this region is affected greatly by capillary number effects (Bozorgzadeh and Gringarten 2006).. The relative permeability curves are dependent on the ratio of viscous to capillary forces.…”

“…The viscous forces are defined by the fluid velocity , and the fluid viscosity , and the capillary forces are represented by the interfacial tension (Bozorgzadeh and Gringarten 2006). As the viscous forces increase and the capillary number is larger, the capillary forces are overcome and the fluid moves through the pores of the rock.…”