Acoustic liquid level tests are performed successfully on many different types of wells throughout the world. The most common application of an acoustic liquid level instrument is to measure the distance to the liquid level in the casing annulus of a well. A less common technique is acquiring an acoustic fluid level by "shooting" the well down the tubing. The results from this type of test on a gas well can be used to determine 1) the amount of liquid and backpressure on the formation, 2) the gas rate into tubing, 3) the equivalent fluid gradient below the liquid level, and 4) the flowing bottom hole pressure. In this paper, surface acoustic data (via shooting down the tubing) and bottomhole data were acquired simultaneously to confirm the calculated results from the acoustic data. The benefit of using the portable fluid level instrumentation is such that it permits a simple cost effective test to be conducted quickly to immediately identify underperforming gas wells due to liquid loading problems. The information obtained during this straightforward test provides critical data in determining the well's potential and the ideal artificial lift technique. Fluid level instruments can be used to inexpensively determine liquid loading and its severity for gas wells as opposed to traditional methods, which are more intrusive and costly.


According to 2004 statistics[1] from the Department of Energy in the US there are 385 thousand natural gas wells producing on average of 126 thousand standard cubic feet of gas per day per well. On average these gas wells are at a stage in their life where the volume of gas being produced continues to decline and all of the liquids are not being lifted to the surface. Very few of these gas wells produce completely dry gas; liquids may be produced from the reservoir and/or both condensate and water can condense as the temperature and pressure decrease as the gas flows to the surface. In the early stages of a gas well's life the flow rate is often high enough that the produced liquids are removed from the wellbore and carried to the surface by the high gas velocity. In the later stages of the well's life liquid accumulates in the bottom of the well as the gas flow rate declines and the gas velocity becomes too low to remove the liquid. As the liquids accumulate in the wellbore additional pressure is applied to the formation and this increased pressures reduces the gas flow from the formation and in some wells the liquid loading bach pressure will increase until eventual all of the gas flow from the well stops.

Flowing gas wells may be characterized as falling in one of three types as illustrated in Fig. 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 and sufficient to establish 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 of the well. In the lower section of the well the flow is characterized as practically zero net liquid flow with gas bubbles or slugs percolating through the liquid and then gas flowing to the surface. Some of these wells may periodically unload liquid from the bottom of the well. As the gas rate is further decreased, even to the point close to ceasing, the concentration of liquid at the bottom of the well increases to more than 90%, while discrete gas bubbles are flowing through the liquid. The Type 3 well diagram represents this condition when there is practically no fluid flowing into the wellbore. Type 3 also includes wells that have been shut-in for an extended time. In shut-in wells 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 papers by Turner[2] for high pressure gas wells, and article by Coleman[3] for lower pressure gas wells.

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