Applicability of Timely Gas Injection in Gas Condensate Fields To Improve Well Productivity

Abstract

Gas-condensate reservoirs suffer losses in well productivity due to near wellbore condensate dropout when the flowing bottomhole pressure declines below the dew point pressure. To alleviate the problem, pressure maintenance and gas cycling are common practices for developing gas condensate reservoirs. A study has been conducted to investigate the applicability of one-time produced gas injection in removing the condensate bank around the wellbore and thereby restoring well productivity. The study focused on two major issues: the optimum time of commencing gas injection and the optimum volume that will remove the condensate bank permanently and restore well productivity. The practice will accelerate the production rate per well and maximize the ultimate hydrocarbon recovery. Three gas-condensate fluid samples with maximum liquid dropout in the range of 6 %, 11 %, and 21 % were used. The benefit of the method was investigated using a full-field compositional reservoir simulation model of a gas condensate field. Reservoir simulation results indicated that, for the lean gases, the best time of starting the gas injection was when the average reservoir pressure around the producing well fell below the maximum liquid dropout pressures. For the rich gas, however, gas injection starting at average reservoir pressure above the maximum liquid dropout pressure resulted in better recovery. The study showed that one-time gas injection not only restored the well productivity and increased reserves but also accelerated the recovery process. These findings bring a different perspective to the development and management of gas condensate reservoirs. Introduction The productivity of wells in gas condensate reservoirs often decreases rapidly as the reservoir is depleted. The decrease is ascribed to a ring of condensate around the wellbore that grows with production time. The ring develops because the flowing bottom hole pressures drops below the dew point pressure of the reservoir gas1. Simulation studies and laboratory studies have indcated condensate saturation near the wellbore as high as 70%. A number of independent investigations have consistently shown that liquid dropout around the wellbore has been the primary reason for losses in well productivity. The presence of liquid around the wellbore reduces the effective permeability to gas2–5. The condensate occupies the gas flow channels and thus impedes gas flow6. The aim of this study has been to assess the impact of a once-off injection of gas in removing the condensate bank and reclaiming well productivity. Whilst condensate dropout translates into losses of revenue due to valuable hydrocarbon components being left in the reservoir, the main focus of the well intervention method is to restore productivity and increase recovery of gas. Single well models have been useful in understanding the phenomenon of condensate dropout or, indeed, in assessing the impact of remedial actions. Nevertheless, they still come short of accurately predicting behaviour on a full field scale. Most single well models are homogeneous or have simplistic reservoir properties and dimensions, in exchange for short simulation time and less complexity in setting them up. In this study, the proposed method was tested on a full field model of a North Sea field. Key questions pertain to timing of the initiation of the gas injection in the life of the reservoir and to determining the gas volumes to achieve maximum benefit. The study was also aimed at establishing the range of applicability of the method by investigating gas condensate fluids with a range of maximum condensate dropouts.

Mitigation of the Effects of Condensate Banking: A Critical Review

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Mitigation of Condensate Banking Using Thermochemical Treatment: Experimental and Analytical Study

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Effects of Hydraulic Fractures on the Treatment of Condensate by Huff-n-Puff Gas Injection in Eagle Ford Shale

“…Compared to the dry gas reservoir, the formation of condensate bank can decrease the well productivity during reservoir pressure depletion. Marokane et al (2002) illustrated the four regions around the wellbore during the development of condensate reservoir. The first region is the farthest from the wellbore in a single phase gas flow, in which the pressure is above the dew point.…”