Solvent Co-Injection in SAGD: Prediction of Some Operational Issues

Abstract In recent years, substantial progress has been made in the theoretical treatment of hydrocarbon dissolution in water, near the critical point of water (374 °C). At these temperatures, water becomes a solvent for gases including the lower hydrocarbons, and possibly, the higher hydrocarbons. The SAGD process is currently the only viable method for in situ recovery of Canada's Athabasca oil sands deposit, a deposit of high viscosity oil in unconsolidated sand. Recent studies have sought to understand modifications at lower steam pressures and gas injection. Most recently, the idea of solvent co-injection has been under discussion. In the present paper, the predictive capabilities that have been developed for gas production in the SAGD process are studied in conjunction with the chemical kinetics and mechanisms of solvolytic reactions. The reactions that produce hydrogen sulphide and carbon dioxide, generally referred to by the name "aquathermolysis, are thought to be solvolytic reactions by their nature. The results of this work suggest strongly that the production of the acid gases, hydrogen sulphide, and carbon dioxide will be suppressed in SAGD operations if a solvent is co-injected. The work has implications for the need for sulphur recovery plants in SAGD projects that are considered for solvent co-injection. Recently published thermodynamic data have made possible the prediction of individual solvent component production or retention in the steam zone. Introduction In 2001, Thimm(1) proposed that gas production in SAGD proceeds via a dissolution mechanism. Gases are dissolved in the produced liquids, and break out of solution in the wellbore and facilities. There has been no case reported so far where it is necessary to assume free gas production in SAGD in order to account for observed gas production or composition. The rationale is as follows. The distribution coefficient (K-value) of a solute gas in equilibrium with a solvent is given by: Equation (Available In Full Paper) In this form, the unit of the Henry's Law coefficient is that of pressure, as is evident from inspection. For the purpose of this work, all Henry's Law constants are given in units of MPa. The equation shows that the K-values are related to the Henry's Law constant. Determination of Henry's Law Constants Henry's Law coefficients for gases in water normally follow a power law known as the Valentiner Equation: Equation (Available In Full Paper) However, at elevated temperatures, this equation begins to fail at about 175 °C, and could only be used for the lowest steam pressure situations. Above this temperature, deviations become progressively larger, because an asymptotic behaviour of the Henry's Law constant near the critical point of water makes an increasingly important contribution. Above 175 °C, the specific volume of water begins to fall significantly from the normal 55.56 mole/L, and Harvey and Levelt Sengers(2) have shown a linear relationship between: Equation (Available In Full Paper) in the range 175 °C and the critical point of water at 374 °C. For small, non-polar molecules and noble gases, Harvey and Levelt Sengers(2) have shown that the use of the equation: Over the last 25 years there have been a number of reports in the literature of planned or executed field tests of the electric heating process, mostly based on the ohmic dissipation of electric energy in the formation. Electrothermic Co., for example, stimulated four wells of the Little Tom field in South Texas

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