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.
Introduction
When there is sufficient reservoir energy and gas wells can be produced at medium to high rates, co-production of liquids is seldom a problem, even at high liquid to gas ratio's (LGR). Although the liquid slips through the gas, effectively the gas-liquid mixture tends to behave like a single phase liquid flowing to surface, where the phases can be separated and processed.
This changes when the reservoir depletes, the reservoir pressure drops and the produced gas rates decline. The velocity at which the gas moves upward approaches the terminal velocity at which liquid droplets would fall downward in a stagnant gas1,2. This means more liquid will be retained in the casing or tubing. The consequence of liquid accumulation in the well is an increase in the hydrostatical pressure drop over the well. Since the well head pressure is usually kept constant by the surface facilities, the increase in pressure drop over the well leads to an increase of the pressure at sand face. In turn an increased pressure at sand face gives rise to a reduction of the inflow of gas and liquids, reducing the gas velocity even further so that more liquid is accumulated. The well is said to load up with liquid and flow ceases altogether (or in the best case some gas continues to bubble upward through a liquid column).
Several approaches have been suggested and tried to prevent or delay the loading process, such as3,4:
Of these approaches, installation of a velocity string, i.e. a small diameter tubing or coiled tubing inside the actual tubing to increase velocity and improve liquid transport, is one of the most attractive options since it is low cost, can be carried out under pressure (i.e. there is no need to kill the well) and requires no further maintenance after installation.
Apart from mechanical considerations, such as interference with the SSSV, the main drawback of the velocity string is that the introduction of the string increases the frictional flow resistance in the well. This inevitably leads to a reduction of the productivity of the well. Hence the price for the suppression of liquid loading is decreased production. This makes selection of the optimum size of the velocity string critical. It has to be selected such that liquid loading is avoided or at least delayed over a considerable period of time, whilst maintaining the highest possible production.
