Abstract
In depleted gas wells, the produced gas rate and consequently the velocity will drop to the extent that produced liquids are no longer carried to surface. The liquids accumulate in the well bore, increasing the sand face pressure. This further reduces the inflow, so that more liquid collects and eventually the flow dies down completely. This phenomenon is known as liquid loading.
Velocity strings are a commonly applied remedy to liquid loading in gas wells. By installing a small diameter string inside the tubing, the flow area is reduced which increases the velocity and restores liquid transport to surface. The disadvantage of the velocity string is the increase in frictional pressure drop, constraining production. Hence an optimal velocity string has to be selected such that liquid loading is delayed over a long period with a minimal impact on production. This requires accurate methods to predict pressure drop in the velocity string as well as tubing-velocity string annulus.
The available methods to predict pressure drop in annuli for gas-liquid flow are modifications of methods to predict wet gas pressure drop in tubing. These modifications are usually based on assumptions, which are strictly valid only for single-phase flow. Their validity for gas-liquid flow is questionable. Hence to assess the validity of the methods a field test was designed and executed. The results were compared with various approaches to describe wet gas flow in an annulus. This allowed selection of the best approach with an accuracy comparable to the accuracy of methods to predict pressure drop in tubing. Factors affecting the accuracy were identified. Comparison with a field case provided further proof for the validity of the approach.
This result is not only relevant for velocity string design, it is important for all annular flow processes in wells such as flow around a stinger, drill pipe, tool or coiled tubing string.
