Laboratory comparison of tertiary N2, CH4, and CO2 injection into an Inland oil field sample

Few laboratory studies compared tertiary gas injection using N2, CH4, and CO2. However, these studies only focussed on oil recovery without examining CO2 storage. This study experimentally compares the oil recovery performance of tertiary N2, CH4, and CO2 injection into a composite Hutton Sandstone core taken from the Inland oil field, Australia. CO2 storage during tertiary CO2 injection is recorded. The core receives an initial injection, which is oil; then a secondary injection, which is water; and finally a tertiary injection, which is N2, CH4, or CO2. Pressure difference across the core and fluid production are recorded. Compositional analysis is performed on the produced oil samples. To estimate oil saturation distribution in the core, numerical simulations are run to simulate the injection experiment. Tertiary oil recovery for CO2 injection is found to be 23.1% of the original oil in-place, which far exceeds the 7.3% for CH4 injection and 5.3% for N2 injection. Ultimate oil recovery was 76.5% for tertiary CO2 injection, 59.6% for tertiary CH4 injection, and 58.3% for tertiary N2 injection. We observed that tertiary oil recovery for each injected gas begins with the oil bank it has generated being produced at a reasonably constant rate after which, the production rate declines reflecting the declining oil concentration in the oil bank. For tertiary CO2 injection, mass transfer between oil and CO2 is observed, which is found to lead to more production of the lighter oil after the oil bank production stage. In addition, tertiary CO2 injection is found to store 0.57 pore volume of the injected CO2 in the core.