Mathematical Model For Liquid Loading In Natural Gas Well Production
Every Natural gas well ceases producing as reservoir pressure depletes. The usual liquid presence in the reservoir can cause further problems by accumulating in the wellbore and reducing production even more. There are a number of options in well completion to prevent liquid loading even before it becomes a problem. Tubing size and perforation interval optimization are the two most common methods. Although completion optimization will prevent liquid accumulation in the wellbore for a certain time, eventually as the reservoir pressure decreases more, the well will start loading. As liquid loading occurs it is crucial to recognize the problem at early stages and select a suitable prevention method. There are various methods to prevent liquid loading such as; mechanical methods (gas lift, plunger lift, pumping and velocity string installation), chemical (foamers), and mathematical simulation. This study is set out to develop a mathematical model – an improvement on previous models – to prevent loading in Natural gas well production.
Conclusion and Recommendation
Liquid loading occurs in gas wells when the produced gas velocity is less than the droplet critical velocity at well-head conditions. The results (Table A1) obtained from this study shows that the best region to evaluate the minimum gas velocity require to prevent the inception of liquid loading is at the wellhead conditions. Thus, the minimum flow conditions necessary to lift the accumulated liquid in the wellbore from the gas wells are provided by the gas velocity sufficient to remove the largest droplet of liquid that can exist which can be calculated using any of the models in this study.
Turner’s model was only able to match the field data after 20% adjustment to the initial model but the model developed for this study does not need any adjustment.
Furthermore, it can also be concluded that the critical gas velocity is independent of pressure and flowing area or diameter of the conduit and the gas velocity depends on density, temperature, interface tension, pressure and conduit diameter thus affecting the distribution and size of droplets.
Above all, in comparison of the minimum, maximum and standard deviation of the percentage relative errors using Turner et al, the new model gave the least of all models in all the conditions
The model developed in this study can be modified to match field data as that done by Turner’s et al by increasing the origin model by 20%.
The effect of impurities in the entrained liquid need to be investigated which could be paramount in determining the critical gas rates for low-pressure gas stripper wells.
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