Water-hot gas injection that uses the waste heat from existing thermal operations can be substantially more energy efficient than CSS and SAGD which require steam generation and water treatment. This project investigated the potential of water-hot gas injection to enhance heavy oil production from Lloydminster heavy oil reservoirs and reduce GHG emissions. The co-injection of water and hot gas at higher temperatures provides a drive component, increases the reservoir temperature, and leads to substantially improved oil recovery as compared to primary production.
Reservoir simulations (using CMG STARS) were performed for a Lloydminster greenfield heavy oil reservoir with 3 horizontal wells. Water-hot gas injection following primary production and 3 CSS cycles was evaluated for pressure drive applications. Flue gas temperatures and compositions in the field depend on the combustion fuel and O2 concentration used for combustion. Different mole% water values (0 to 90%), N2/CO2 ratios (0 to 7.43), and temperatures (80 to 450 °C) were investigated in order to evaluate many of the available options.
Although oil production for water-hot gas injection was much lower than for steam-only injection, the energy injected/m3 of oil produced was reduced by an order of magnitude and this energy was recovered from waste flue gas. For water-hot gas injection, both oil production and energy injected/m3 of oil increased with increasing injection temperature, increasing mole% water, and decreasing N2/CO2 ratio in the injection fluid. The steam oil ratio (SOR) was ~0.6 m3 CWE/m3 oil and decreased gradually with injection temperature.
Water-hot gas was more effective than hot gas injection as water addition to flue gas increased oil production due to the heat of vaporization that it transferred to the reservoir. CO2 in the hot gas was more effective than N2. Decreasing the N2/CO2 ratio increased oil production because of the greater solubility of CO2 and its higher molar specific heat as compared to N2. The difference in oil production between water-hot gas and hot gas injection increased with temperature.
There was an optimum hot gas injection rate as too high a rate interfered with oil flow and reduced its production. Use of vent wells to remove excess gas and injector well pulsing were unsuccessful operating strategies. The potential of using waste flue gas energy for water-hot gas injection in Lloydminster greenfield heavy oil reservoirs to enhance oil production as compared to continued primary production, improve energy efficiency, and reduce GHG emissions was demonstrated.
Reservoir simulations were also performed to determine the effect of water-gas injection following CHOPS. Wormholes, which grew extensively from vertical wells during primary production, provided enhanced reservoir access, substantially improved injectivity, and supported transfer of heat into the reservoir. Both pressure drive and cyclic water-hot gas injection processes significantly increased oil production as compared to continued primary production following CHOPS. The pressure drive water-hot gas process was substantially better than cyclic injection as a result of the formation of an oil bank and downward displacement of oil by hot gas. The recovery factor for water-hot gas injection in drive mode was as high as 25.8% for 20 mole% water and 80 mole% gas at 185 °C and 30.5% for 80 mole% water and 20 mole% gas at 160 °C. Heavy oil production increased with increasing injection temperature.