Comprehensive Research of Scaling Prediction for Gas Reservoir Fluid considering Phase State. (11th February 2019) - Zheng, Heng; Pu, Chunsheng
Abstract : During the exploitation of a gas reservoir containing water, the scaling problem is usually affecting the gas production in gas wells. Although the scale formation that occurs during oil field development is quite different from the aforementioned gas field, the phase behavior plays a pivotal role in the formation of inorganic scale in gas field development. It is a well-known fact that there is no device that can directly measure the extent of scaling formation in a high-temperature and high-pressure reservoir. At the same time, the commonly applied scaling prediction method does not account for the fluid phase state. In this work, the scaling condition and alteration in controlling parameters in an actual gas reservoir were studied by self-developed high-temperature and high-pressure formation fluid equipments. From thermodynamics, a new scaling prediction model for the multiphase equilibrium of gas reservoir fluid is proposed that considers gas, liquid hydrocarbon, formation water, and inorganic salt scale. For the complexity of the direct solution for a phase equilibrium system with a chemical reaction, a simplified method for calculating the phase change and chemical equilibrium in a multiphase equilibrium system with chemical reactions is proposed based on the conservation of materials and the unification of the physical properties of components. The results show that the predicted value of the model was consistent with the experimental results. The new scaling prediction model considered the influence of the phase state which can accurately predict the change of the fluid phase state and the amount of inorganic salt scaling of actual gas reservoir fluids under the condition of multiphase equilibrium. Moreover, the average deviation of the prediction results is about 3%. The predicted scaling amount of the model without considering the effect of phase change is significantly lower than that of the experimental results. More specifically, the average deviation is around 30%. With the decrease of gas reservoir pressure, formation water evaporation intensifies under the influence of the oil and gas phase state, which leads to the increase of the formation water ion concentration when the influence of the fluid phase change is not considered. Then, the prediction of the inorganic salt scaling will be significantly lower.