Abstract

Liquid buildup in the wellbore has long been recognized as being detrimental to flow from gas wells. This paper will discuss a programmed approach for analyzing liquid loading problems and for selecting the optimal artificial lift method to be used once a liquid loading problem occurs. This paper discusses factors affecting methods to alleviate liquid loading problems and guidelines for selecting in advance the optimum method to be used when liquid loading occurs.

Introduction

The presence of a liquid phase during gas production has long been recognized as a detriment production has long been recognized as a detriment to flow from gas wells. A gas well begins to load up with liquids when the velocity of the gas phase in the tubing becomes insufficient to transport the liquid phase to the surface. Once this occurs, the liquids will begin to accumulate at the bottom of the production string imposing an additional back pressure against the formation, which will impede, if not halt all together, gas production. production. Several unloading techniques have been shown to be effective in the removal of liquids from the wellbore. The more commonly used methods included rod pumping, gas lift, plunger lift, foaming agents, alternate flow/shut-in periods, the use of smaller diameter production tubing and swabbing. The operator is faced with matching the capabilities of the above methods with the needs and production characteristics of the wells that may loadup with liquids. The objectives of this paper are to identify and discuss techniques used to alleviate liquid loading problems and the factors affecting the choice of the optimum lift method to be employed once fluid entry occurs.

Statement of the Problem

The presence of a liquid phase during gas production has long been recognized as a detriment production has long been recognized as a detriment to flow from gas wells. A gas well begins to load up with liquids when the velocity of the gas phase in the tubing becomes too small to transport the liquid phase, either formation water or condensate, to the surface. Once the velocity of the gas phase becomes insufficient to carry the liquid phase, the liquids will begin to accumulate at the bottom of the wellstring and imposing an additional back pressure against the formation, which will impede, if not halt all together, gas production. production. This process of liquid loading or heading can be summarized in the following four stages: Stage 1: Upon initial completion, a gas well normally has sufficient gas velocity to transport the liquids to the surface. At this stage, the gas velocity is greater than or equal to the minimum required gas velocity necessary for the continuous removal of liquids from a gas well. This is normally the longest lasting stage due to the high initial reservoir pressure and high initial gas flow rate. Figure 1A shows the liquid droplets to be suspended in the high velocity gas core being transported to the surface. Stage 2: As time passes, the reservoir pressure will decrease resulting in a decreased pressure will decrease resulting in a decreased gas flow rate. Since the gas velocity is directly proportional to the gas flow rate, the gas proportional to the gas flow rate, the gas velocity will subsequently decrease. Once the gas velocity falls below the critical gas velocity necessary to continuously remove the liquids, the droplets suspended in the gaseous phase will begin to move downward and accumulate at the bottom of the well. This phenomenon restricts the effective flow area for the gas and impedes gas production. Figure 1B shows the liquid beginning to accumulate at the bottom of the wellbore. The operator should notice a decrease in gas production during this stage.

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