This work focuses on evaluating the effect of the steam quality on the upgrading and recovering extra-heavy crude oil in the presence and absence of two nanofluids. The nanofluids AlNi1 and AlNi1Pd1 consist of 500 mg·L−1 of alumina doped with 1.0% in mass fraction of Ni (AlNi1) and alumina doped with 1.0% in mass fraction of Ni and Pd (AlNi1Pd1), respectively, and 1000 mg·L−1 of tween 80 surfactant. Displacement tests are done in different stages, including (i) basic characterization, (ii) waterflooding, (iii) steam injection at 0.5 quality, (iv) steam injection at 1.0 quality, (v) batch injection of nanofluids, and (vi) steam injection after nanofluid injection at 0.5 and 1.0 qualities. The steam injection is realized at 210 °C, the reservoir temperature is fixed at 80 °C, and pore and overburden pressure at 1.03 MPa (150 psi) and 5.51 MPa (800 psi), respectively. After the steam injection at 0.5 and 1.0 quality, oil recovery is increased 3.0% and 7.0%, respectively, regarding the waterflooding stage, and no significant upgrade in crude oil is observed. Then, during the steam injection with nanoparticles, the AlNi1 and AlNi1Pd1 increase the oil recovery by 20.0% and 13.0% at 0.5 steam quality. Meanwhile, when steam is injected at 1.0 quality for both nanoparticles evaluated, no incremental oil is produced. The crude oil is highly upgraded for the AlNi1Pd1 system, reducing oil viscosity 99%, increasing the American Petroleum Institute (API)° from 6.9° to 13.3°, and reducing asphaltene content 50% at 0.5 quality. It is expected that this work will eventually help understand the appropriate conditions in which nanoparticles should be injected in a steam injection process to improve its efficiency in terms of oil recovery and crude oil quality.

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A selection flowchart that assists, through Computational Fluid Dynamics (CFD) simulations, the design of microfluidic experiments used to distinguish the performance in Chemical Enhanced Oil Recovery (CEOR) of two surfactants with very similar values of interfacial tension (IFT) was proposed and its use demonstrated. The selection flowchart first proposes an experimental design for certain modified variables (: porosity, grain shape, the presence of preferential flowing channels, and injection velocity). Experiments are then performed through CFD simulations to obtain a set of response variables (: recovery factor, breakthrough time, the fractal dimension of flow pattern, pressure drop, and entrapment effect). A sensitivity analysis of regarding the differences in the interfacial tension (IFT) can indicate the CFD experiments that could have more success when distinguishing between two surfactants with similar IFTs (0.037 mN/m and 0.045 mN/m). In the range of modifiable variables evaluated in this study (porosity values of 0.5 and 0.7, circular and irregular grain shape, with and without preferential flowing channel, injection velocities of 10 ft/day and 30 ft/day), the entrapment effect is the response variable that is most affected by changes in IFT. The response of the recovery factor and the breakthrough time was also significant, while the fractal dimension of the flow and the pressure drop had the lowest sensitivity to different IFTs. The experimental conditions that rendered the highest sensitivity to changes in IFT were a low porosity (0.5) and a high injection flow (30 ft/day). The response to the presence of preferential channels and the pore shape was negligible. The approach developed in this research facilitates, through CFD simulations, the study of CEOR processes with microfluidic devices. It reduces the number of experiments and increases the probability of their success.

In the oil and gas industry, there has not been a consistent, concerted effort to reduce global greenhouse gas (GHG) emissions across the supply chain. In addressing this challenge, this study evaluates the potential GHG emissions reduction that may be realized through deployment of a geothermal power co-production system in two Colombian oil fields, compared to a base case where energy needs are derived through non-renewable sources such as gas and diesel. These geothermal power co-production systems make use of organic Rankine cycle (ORC) engines to convert the heat from produced oilfield fluids into electrical energy. The energy potential of this resource is evaluated through the exergy concept, and a life cycle analysis is implemented to calculate the carbon footprint using the Intergovernmental Panel on Climate Change (IPCC) 2013 methodology. In the two oil fields of interest, OFA and OFB, the results show a maximum potential energy production of 2260 kWe for OFA and 657 kWe for OFB. The co-production of crude oil and electrical energy from geothermal resources suggests a possible a carbon footprint reduction of 19% and 11% for OFA and OFB, respectively, when compared to conventional power systems. In addition, four emissions scenarios are assessed where the current energy sources in these oil fields are substituted by gas, diesel, co-generated geothermal power, or a combination of the three while maintaining the average power output in each field. The highest carbon footprint reduction is found in Scenario 1, which replaces 100% of the liquid fuel consumption with purchased gas (gas provided by a third party and treated outside the system’s limits), thereby achieving carbon footprint reductions up to 54% for OFB. This research opens the prospect for the use of renewable energies in the oil and gas industry.

This work aimed to develop SiO 2 nanoparticles functionalized with amine (SiO 2 /amine) to inhibit the chemical degradation of partially hydrolyzed polyacrylamide (HPAM) in the presence of different ionic species through static experiments and molecular simulations. The effect of the SiO 2 /amine on the rheological behavior of HPAM solution was evaluated in the presence of monovalent, divalent, and trivalent cations. To understand the relationships between polymers, ions, and nanostructures, interaction energies and the radii of gyration under all saline scenarios were calculated by molecular dynamics (MD). The SiO 2 /amine was spherical with a size <100 nm. There is a correlation between the ion's valence and the chemical degradation of HPAM: in the presence of polyvalent cations, the viscosity losses of the HPAM solutions reached up to 94%, incorporating SiO 2 /amine at 100 mg L −1 mitigated the viscosity losses by up to 16%. The molecular simulations showed that the self-folding of the HPAM chains increased in brine containing trivalent cations leading to the viscosity loss of the solutions. The presence of SiO 2 /amine increased the radius of gyration of the polymer up to 17%, improving the viscosity of the HPAM solutions. This study opens a broader landscape regarding nanotechnology to improve polymer flooding applied to the oil industry.