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.

Interfacially active carbon nanotube hybrids (nanohybrids) exhibit promising properties for potential applications in reservoir systems. They could be used as modifiers of transport properties as well as nanoscale vehicles for catalyst and contrast agents. In situ catalysis might be used to modify interfacial tension and wettability of the rock wall. The main requirements for any of these applications are the ability to form stable dispersions and to effectively propagate through the reservoir porous medium under the temperature and salinity conditions that are typical in commercial operations. In this work, suspensions of purified multi-walled carbon nanotubes (P-MWNTs) in deionized water and high-salinity brine have been prepared using two commercially available polymers, polyvinyl pyrrolidone (PVP) and hydroxyethyl cellulose (HEC-10). Stable dispersions were put in contact with crushed Berea sandstone, quantifying the amount of nanotubes lost from suspension to estimate the adsorption of these nanotubes from suspension onto the walls of the reservoir rocks. Adsorption isotherms were measured from room temperature up to 80 °C from aqueous suspensions with salinities up to 10%. These studies demonstrate that combining these two polymers stabilizes suspensions in high-salinity water and minimizes adsorption on the sand walls. It is proposed that this optimized behavior is due to additive electrostatic and steric repulsions. While the polar PVP helps disaggregation by effectively wrapping individual nanotubes (primary dispersant), the bulky HEC-10 inhibits the reaggregation in saline solutions (secondary dispersant). Column experiments were conducted to study the propagation of these suspensions through porous media. It was found that a small amount of nanohybrids adsorbed to the sand will be able to saturate available adsorption sites, resulting in subsequent injections of nanohybrids to be propagated completely through the column without adsorption. In that sense, we were able to reach 100% of the injected concentration with a low particle concentration of 100 ppm and total particle adsorption to the sand of less than 10% at room temperature.

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Carbon dioxide flooding of oil fields around the world is proven as a successfully adopted practice in increasing oil production particularly in marginal wells with low production rates. However, the limitations of this technology lie in the limited supply of carbon dioxide, high capital cost, and infrastructure corrosion. In this work, we present an alternative CO2 flooding method which generates CO2 inside the reservoir to increase oil recovery. The process involves the injection of a concentrated CO2 producing solution of ammonium carbamate (AC). Chemical solvent CO2 capture technology was widely used for years. Carbamates were formed when aqueous amines absorbed CO2. The new proposed in situ CO2 generation EOR technique provides a way to directly apply the product of the CO2 capture technology for outstanding tertiary recovery. Ammonium carbamate (CH6N2O2), highly water-soluble chemicals, can dissociate at reservoir temperature producing carbon dioxide and ammonia. The carbon dioxide migrates to the oil phase, causing oil phase swelling and reducing oil viscosity, and therefore increasing oil production. The ammonia dissolves in the water, and the ammonia-water solution increases the water wettability of the rock. Flow experiments were conducted using 6" Ottawa sand packs. The experiments demonstrated that the decomposition of a 35% AC solution injected to the sand packs resulted in further lowering of the residual oil saturation following a standard water flood. The tertiary recovery in the high-pressure sand pack experiments was found to average 27%. In the proposed process, AC can be dissolved in produced reservoir fluids or seawater and injected into the reservoir to generate CO2 in situ and increase oil production as it decomposes. The benefits of this process compared to CO2 flooding lie in the simplicity of adapting this technology to an existing waterflood, and the lack of the complicated infrastructure needed in a typical CO2 project, such as compression and gas handling facilities. An additional advantage lies in the ability to deliver the CO2 in the form of a room temperature solid, alleviating the need for a pipeline.

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