Abstract

The loss of productivity due to liquid blockage in gas wells is a common problem. Dropout of condensate from gas and/or water accumulates in the pores of the rock near a producing well or within a hydraulic fracture, causing a significant reduction in gas relative permeability, curtailing production. As a solution to this problem, we have developed a chemical treatment designed to increase flow rates of blocked gas wells. The treatment alters the wettability of the solid surface, minimizing capillary pressure and increasing the relative permeabilities of gas and condensate. In laboratory core flood experiments, application of this chemical treatment increased flow rates by a factor of about 2 for two-phase flow of gas and condensate, gas and water, and gas and volatile oil. To bring this technology from the laboratory into the field, we stimulated a blocked gas well. The initial results of this field trial are reported in this paper and demonstrate the treatment was highly effective.

Introduction

Over time, many gas wells reach a point where flow rates are reduced due to the accumulation of oil, condensate and/or water blockage and may eventually become uneconomic. In gas condensate reservoirs, liquid begins forming as the pressure drops below the saturation or dewpoint pressure of the gas (Afidick et al., 1994; Ayyalasomayajula et al., 2005). Since the largest pressure drop occurs near the producing well, the formation of this condensate phase usually starts near the wellbore. The condensed liquid becomes trapped by capillary forces and is retained in the rock as a result of low liquid mobility. Production avenues in the formation are subsequently blocked, reducing relative permeability to gas and causing production to decline. This loss of productivity due to liquid blockage is an especially serious problem for rich condensate gases. Depending on the reservoir's fluid composition, pressure and temperature, the liquid dropout from the gas phase may be as high as 30–40%.

Even for dry gas wells, a 1% liquid dropout reduces production significantly which has been reported to decline by a factor of 2 to 4 as a result of condensate accumulation (Afidick et al., 1994).

Hydraulic fracturing is commonly used to increase well productivity but has limitations. One such limitation is significant condensate saturation will simply buildup in the fracture reducing conductivity (Mohan, 2005). In fields where there is significant liquid blockage in the formation, fracturing is not always effective. Other conventional methods such as gas, microemulsion, surfactant or solvent injection may also prove only marginally effective. There is a need for an inexpensive, durable and alternative solution to this common problem.

A new approach under development is the use of an innovative chemical treatment solution to alleviate liquid blockage (Kumar, 2006; Kumar et al., 2006; Bang, 2007; Bang et al., 2008; Bang et al., 2009). The treatment solution consists of an active chemical in a solvent that is brine tolerant. The active chemical is a non-ionic polymeric fluorinated surfactant that is non-reactive, but interacts with the substrate under reservoir conditions to alter the wettability of the surface. This change in wettability increases the relative permeabilities of gas and condensate (Bang et al., 2006). The selection of an appropriate solvent mixture to deliver the chemical is an important part of the chemical treatment. A mixture of 2-butoxyethanol and ethanol was used as the solvent in this application. More details about the chemistry of the fluorochemical, alternative solvents and the method of selecting solvents can be found in Bang (2007) and Bang et al., (2008).

In extensive laboratory experiments (at field pressures, temperatures and flow rates) application of the experimental treatment increased gas and condensate flow rates in core samples by about 1.5 to 3.0 times over an extended time, without plugging or other undesirable effects (Bang, 2007). These treatments have been shown to be durable for thousands of pore volumes of subsequent flow of the gas-condensate/oil fluid.

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