Abstract

Gas wells require continuous checking to insure that the wells are being produced at optimum conditions. Water or liquid accumulation in the wellbore will restrict gas production. The acoustic liquid level test offers an inexpensive non-intrusive testing procedure for determining wellbore conditions so that optimization of producing conditions can be performed. Examples of surface acoustic tests on operating gas wells that are above and below critical flow rates are shown and discussed. These acoustic tests help the operator visualize present operating conditions and to implement a better operating technique to improve production and well operations if needed. The new procedure involves monitoring fluid level and pressure in the tubing during a short term test sequence. Tests clearly show the redistribution of flowing gas and liquid and allow the construction of the corresponding tubing pressure traverse and the determination of the flowing gas/liquid ratio, liquid fallback volume and flowing BHP.

Introduction

Flowing gas wells may be characterized as falling in one of three types as illustrated in Figure 1. In the first case (Type 1) any liquid being produced with the gas or condensing due to temperature and pressure changes is uniformly distributed in the wellbore. The gas velocity is sufficient to continuously carry liquid as a fine mist or small droplets to the surface, establishing a relatively low and fairly uniform flowing pressure gradient. In the second case (Type 2) the gas velocity is not able to uniformly carry sufficient liquid to the surface resulting in a higher percentage of liquid accumulating in the lower part of the well. The flowing pressure gradient will show dual values, a low gradient (close to that of the flowing gas) above the gas/liquid interface and a higher gradient in the lower section ofthe well. In the lower section of the well the flow is characterized as practically zero net liquid flow with bubbles or slugs of gas percolating through the liquid and then gas flowing to the surface. As the gas rate is further decreased, even to the point close to ceasing, the concentration of liquid at the bottomof the well is greater than 90 % and discrete gas bubbles are lowing through the liquid. The Type 3 well diagram represents this condition when there is practically no flow into the wellbore. In this case the combination of the tubing head gas pressure plus the gradient of the liquid column may temporarily exceed the reservoir pressure causing liquid to back flow into the formation.

Knowledge of the flowing gradient and fluid distribution in the well is of paramount importance in determining whether inflow from the formation is being restricted by excessive liquid in the flow string, thus requiring application of some deliquifying technique such as installation of plungers, pumps or redesign of the flow string to increase gas velocity. For further details on liquid loading of gas wells please refer to the following papers: SPE2198 by Turner1 for high pressure gas wells, and article by Coleman2 in Journal of Petroleum Technology of 1991 for lower pressure gas wells.

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