The carbon dioxide flooding of oil reservoirs represents one of the most-proven tertiary oil recovery practices. However, there are significant challenges associated with applying CO 2 flooding in certain onshore or offshore fields and applications. The common challenges include a limited supply of CO 2 , transportation, capital cost investment, and corrosion. For offshore flooding, the critical challenge could be more related to extreme remote and significant project cost increase. In this work, we investigated delivering CO 2 indirectly to the subsurface formation by injecting the concentrated solution of ammonium carbamate (AC) as CO 2 generated species. Ammonium carbamate, a highly water soluble solid (40 wt %) and commercially available, can be dissolved in aqueous solution and injected to the reservoir where it decomposes at reservoir condition, thus releasing products of CO 2 and ammonia. The produced CO 2 results in lowering oil viscosity and oil swelling. Increase of ammonia concentration also lead to sand wettability reversal due to elevated alkalinity. Tertiary oil recovery performance of ammonium carbamate solution was evaluated by conducting multiple sand packs and core flooding test at various pressure and temperature conditions. Dodecane and several dead crude oils were used as oil phase. Injected AC concentrations tested were ranging from 5 to 35 wt %, with operational pressure, pressure (P) ranging from atmospheric to 4000 psi, and the preset temperature ranging from 96 to 133 °C. The average tertiary recovery observed from all the tests was found to be 29%. Results of laboratory experiments clearly demonstrated the potentials of this novel formulation for tertiary oil recovery. Mainly, it requires minimal capital investment up-front in comparison to CO 2 flooding and largely eliminates the occurrence of gravity segregation and reduces adverse fingering behaviors because there is no presence of a free-CO 2 phase involved. This endeavor serves as a successful proof of concept for the potential applications in tertiary oil recovery for both onshore and offshore fields.
Flue gas flooding is one of the important technologies to improve oil recovery and achieve greenhouse gas storage. In order to study multicomponent flue gas storage capacity and enhanced oil recovery (EOR) performance of flue gas water-alternating gas (flue gas–WAG) injection after continuous waterflooding in an oil reservoir, a long core flooding system was built. The experimental results showed that the oil recovery factor of flue gas–WAG flooding was increased by 21.25% after continuous waterflooding and flue gas–WAG flooding could further enhance oil recovery and reduce water cut significantly. A novel material balance model based on storage mechanism was developed to estimate the multicomponent flue gas storage capacity and storage capacity of each component of flue gas in reservoir oil, water and as free gas in the post-waterflooding reservoir. The ultimate storage ratio of flue gas is 16% in the flue gas–WAG flooding process. The calculation results of flue gas storage capacity showed that the injection gas storage capacity mainly consists of N2 and CO2, only N2 exists as free gas phase in cores, and other components of injection gas are dissolved in oil and water. Finally, injection strategies from three perspectives for flue gas storage, EOR, and combination of flue gas storage and EOR were proposed, respectively.
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