This paper introduces an improved model for describing the liquid loading process in gas wells. The model is an extension of the model proposed by Dousi et al (2005).
The Dousi model handles the downhole inflow and outflow between the well and the reservoir in a simple manner. The new model improves this aspect, and makes more realistic and detailed assumptions with respect to the production and injection interval. Analysis using this new model improves understanding of the processes occurring downhole. Also it can be used to predict future behaviour of the well in a more realistic fashion. As in the Dousi model, two typical flowrates could be found, one at full production with all the fluids produced to the surface and one meta-stable rate where produced fluids are being re-injected into the reservoir. Field observations confirm the existence of two possible flowrates in many wells. The difference between the new model and the Dousi model is that changes in flow rates occur more slowly when liquid loading starts, reflecting the more realistic inflow performance assumptions.
With this model, liquid loading processes in the well can be better understood and predicted. This is important for optimisation of well performance and the economic assessment of the well and field.
In maturing gas fields, liquid loading is a serious problem. The liquid loading process occurs when the gas velocity within the well drops below a certain critical gas velocity. The gas is then unable to lift the water co-produced with the gas (either condensed or formation water) to surface. The water will fall back and accumulate downhole. A column is formed which imposes a back pressure on the reservoir and hence reduces gas production. The process eventually results in intermittent gas production and the well dies.
The liquid loading phenomenon is known for many years. A number of papers have appeared describing the process and giving options to tackle the loading of the well. The first breakthrough in understanding the process was made by Turner et al. (1969). They created two models for the transport of the liquids, one for the transport via a liquid film on the wall of the tubing where the upward movement is created by interfacial shear, the other of entrained liquid droplets in a vertically moving gas stream. The minimum gas velocity to remove all the liquids out of the well was lowest in the second model, the liquid drop model. The droplet model predicts the free falling velocity of the biggest droplet in the flow. The minimum gas velocity to remove all the liquids is assumed to be above the free falling velocity of that droplet. This is referred to as the critical Turner rate (Turner et al. 1969).
The symptoms of liquid loading were discussed by Lea & Nickens (2004). According to them liquid loading is recognizable by:
sharp drops in a decline curve;
onset of liquid slugs at the surface;
increasing difference between the tubing and casing pressures with time;
sharp changes in gradient on a flowing-pressure survey.
Possible ways to reduce liquid loading are also discussed by Lea & Nickens (2004). These include: production string sizing in which a smaller tubing size is chosen to increase the gas velocity above the critical Turner rate; compressor installation which lowers the tubing head pressure to increase the gas velocity above the critical Turner rate; plunger lift to lift all the liquids using the gas pressure during shutdown of the well; pump installation to pump up the liquids during production; foaming the liquids so that it is easier for the gas to lift all the fluids thus reducing the critical Turner rate; and gas lifting using gas from other wells without liquid loading to decrease the pressure loss in the tubing and increasing the velocity. The best solution for a given well depends on the properties of that particular well.