Hot water chemical flooding involves injecting 0.5 PV of 80°C hot water at 60% water cut, along with 0.2 PV of 2 mPa·s polymer and 0.4 PV of 2% surfactant. This leads to significant oil displacement and a decrease in water cut at the production well. Water cut rises after polymer injection stops and slows after surfactant injection stops. Later, water cut slightly increases when hot water injection stops. Final oil recovery is 41.1%, a 6.3% increase over water flooding
Hot water chemical flooding involves injecting 0.5 PV of 80°C hot water at 60% water cut, along with 0.2 PV of 2 mPa·s polymer and 0.4 PV of 2% surfactant. This leads to significant oil displacement and a decrease in water cut at the production well. Water cut rises after polymer injection stops and slows after surfactant injection stops. Later, water cut slightly increases when hot water injection stops. Final oil recovery is 41.1%, a 6.3% increase over water flooding
Abstract
Chemical agents (polymer and surfactant) assisted hot water flooding is an effective means of enhancing oil recovery in heterogeneous and heavy oil reservoirs. The rapid prediction of oil recovery through hot water chemical flooding is very important. The stream tube model is a fast analytical method for predicting water flooding recovery, but it is not suitable for hot water chemical flooding. In this paper, a permeability distribution model for multi-stream tubes is established based on permeability variation coefficient using normal distribution function for reservoir heterogeneity, using Gompertz growth function model to characterize the changes in stream tube temperature, polymer viscosity, and surfactant concentration with injection volume, using Brooks–Corey model to describe the influence of interfacial tension and temperature on the relative permeability curve. Finally, an analytical stream tube model for hot water chemical flooding of heavy oil reservoirs was established. The time-discrete method is used to solve the model, and then, the graphs of the relationship between oil recovery and water cut are obtained. Compared with numerical simulation methods, the prediction error of oil recovery is less than 2%, and the calculation time is reduced by 89%. This model has been successfully applied to X oilfield. Based on historical fitting, it is predicted that hot water chemical flooding can enhance oil recovery by 6.3% compared to water flooding. This paper provides a fast calculation method for predicting and evaluating the effectiveness of hot water chemical flooding in heavy oil reservoirs.
