Abstract

In oil and gas field operations, the dynamic interactions between reservoir and wellbore cannot be ignored, especially during transient flow in the near-wellbore region. A particular instance of transient flow in the near-wellbore region is the intermittent response of a reservoir that is typical of liquid loading in gas wells. Despite the high level of attention that the industry has devoted to the alleviation of liquid loading, the fundamental understanding of the associated phenomena is still surprisingly weak. This applies not only to the flows in the wells, but also to the ways in which these flows interact with those in the reservoir. The classical way of dealing with these interactions, inflow performance relationships (IPRs), relate the inflow from the reservoir to the pressure at the bottom of the well, which is related to the multiphase flow behavior in the tubing. These relationships are usually based on steady-state or pseudo steady-state assumptions.

However, such IPRs may be inadequate when a transition from an acceptable liquid loading regime to an unacceptable occurs over a relatively small range of production rates and, hence, over a relatively short time. The most satisfactory solution would be to couple a transient model for the reservoir to a transient model for the well. This paper presents the results of a numerical modeling effort focused on the identification of the transient pressure profile in the near-wellbore region during fully transient flow conditions. The preliminary results, obtained for a single-phase (gas) situation and for a three-phase (oil-water-gas) situation, show a "U-shaped" pressure profile along the reservoir radius. The existence of a similar pressure profile could be the explanation for the reinjection of the heavier phase into the reservoir during liquid unloading in gas wells.

Introduction

Liquid loading in gas wells is one of the particular instances of transient flow in both the wellbore and the near-wellbore region. Liquid loading occurs when the reservoir pressure decreases in mature gas fields and the liquid content of the well and its particular distribution at the given instant in time create a backpressure that restricts, and in some cases even stops, the flow of gas from the reservoir. Liquid loading is an all too common problem in mature gas fields around the world. In the USA alone at least 90% of the producing gas wells encounter such problems, at least occasionally. Such is the importance of liquid loading that the industry has devoted a lot of attention to the alleviation of the problem using various measures. However, the fundamental understanding of the associated phenomena is still surprisingly weak. This applies not only to the flows in the wells, but also to the ways in which these flows interact with those in the reservoir. The classical way of dealing with these interactions is through inflow performance relationships (IPRs) where the inflow from the reservoir is related to the pressure at the bottom of the well, which is related to the multiphase flow behavior in the well (and in the rest of the production system, if appropriate). The latter is also usually calculated from steady-state relationships (though these often lack a fundamental basis). However, a transition from an acceptable liquid loading regime to an unacceptable one may occur over a relatively short time. Flow at the surface will remain in mist or annular flow regime till the conditions change sufficiently to exhibit characteristics of phenomena transitional flow. At this point, the well production becomes somewhat erratic, progressing to slug and churn flow, while following an overall decreasing trend. As a result, the liquids start to dynamically accumulate in the wellbore, causing downhole pressure fluctuations. The increasing liquid holdup augments the backpressure on the formation, which ultimately accounts for the well's death.

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