An Improved Model for the Liquid-Loading Process in Gas Wells
- Frank Raymond Van Gool (Delft U. of Technology) | Peter K. Currie (Delft U. of Technology)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- November 2008
- Document Type
- Journal Paper
- 458 - 463
- 2008. Society of Petroleum Engineers
- 5.6.8 Well Performance Monitoring, Inflow Performance, 4.6 Natural Gas, 3.1.5 Plunger lift, 5.2.1 Phase Behavior and PVT Measurements, 5.7.5 Economic Evaluations, 3.1.6 Gas Lift, 5.2 Reservoir Fluid Dynamics, 4.1.6 Compressors, Engines and Turbines, 4.2 Pipelines, Flowlines and Risers, 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 6.5.2 Water use, produced water discharge and disposal
- liquid loading
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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. (2006).
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 of the results this new model produces improves the understanding of the processes occurring downhole. This analysis can also be used to predict future behavior of the well in a more realistic fashion. As in the Dousi model, two typical flow rates could be found, with one at full production with all the fluids produced to the surface and the other one a metastable rate in which produced fluids are being reinjected into the reservoir. Field observations confirm the existence of two possible flow rates 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 understood better and predicted. This is important for optimization of well performance and for 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 coproduced 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 backpressure on the reservoir and, thus, reduces gas production. The process results eventually in intermittent gas production, and then the well dies.
The liquid-loading phenomenon has been known for many years. A number of papers have been published 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 transport by way of a liquid film on the wall of the tubing where the upward movement is created by interfacial shear, and the other by way of entrained liquid droplets in a vertically moving gas stream. The minimum gas velocity to remove all the liquids from the well was lowest in the second model, which is the liquid-droplet 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 and Nickens (2004). According to them, liquid loading is recognizable by sharp drops in the decline curve, onset of liquid slugs at the surface, an increasing difference between the tubing and casing pressures with time, and sharp changes in gradient on a flowing-pressure survey.
Possible ways to reduce liquid loading are also discussed by Lea and 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 that lowers the tubinghead pressure to increase the gas velocity above the critical Turner rate; a plunger lift to lift all the liquids by use of 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 by use of gas from other wells that have no liquid loading to decrease the pressure loss in the tubing and increase the velocity. The best solution for a given well depends on the properties of that particular well.
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Cullender, M.H. and Smith, R.V. 1956. Practical Solution of Gas-Flow Equations or Wells and Pipelines With LargeTemperature Gradients. Trans., AIME, 207: 281-287.
Dousi, N., Veeken, C.A.M., and Currie, P.K. 2006. Numerical and Analytical Modeling ofthe Gas-Well Liquid-Loading Process. SPEPO 21 (4): 475-482.SPE-95282-PA. doi: 10.2118/95282-PA.
Lea, J.F. and Nickens, H.V. 2004. Solving Gas-Well Liquid-LoadingProblems. JPT 56 (4): 30-36. SPE-72092-MS. doi:10.2118/72092-PA
Turner, R.G., Hubbard, M.G., and Dukler, A.E. 1969. Analysis and Prediction of MinimumFlow Rate for the Continuous Removal of Liquids From Gas Wells. JPT21 (11): 1475-1482; Trans., AIME, 246. SPE-2198-PA. doi:10.2118/2198-PA.