(614a) Molecular Dynamics Simulation As an Aid for Enhanced Oil and Gas Recovery in Tight and Shale Reservoirs

Enhanced Oil and Gas Recovery processes (EOR/EGR) have been widely investigated for the past few decades as potential technologies for increasing production of reservoirs. However, many underlying physical mechanisms of such processes are still unclear and molecular simulation is an essential tool in understanding such mechanisms and phenomena. When dealing with tight and shale reservoirs, an extra factor is added as the properties of fluids under confinement differ largely from those in bulk condition. Two main examples of EOR/EGR processes are CO₂ reinjection and water flooding. Regarding CO₂ reinjection, oil and gas fields have shown to be a secure and well-characterized alternative to store carbon,¹ directly contributing to reducing the emission of greenhouse gases. The reinjection of CO₂ into hydrocarbon reservoirs has also shown to contribute to oil and gas recovery. In our recent work,² local impact of the presence of CO₂ in calcite nanopores containing n-alkanes of variable size was studied through molecular simulation and adsorption analysis. In all the cases investigated, the stronger interactions and affinity of CO₂ with the calcium sites on the calcite surface led to the replacement of the adsorbed n-alkanes by CO₂. This leads to an indication that the reinjection of CO₂ into calcite reservoirs might enhance oil and gas recovery. Such a trend has also been observed experimentally³ as, for example, in the preferential adsorption of CO₂ over methane in pink limestone rock.

To understand completely the mechanisms involved in the reinjection of CO₂ into hydrocarbon reservoirs, we should not only focus on equilibrium properties but also on transport properties. With this in mind, we performed molecular dynamics simulations of hydrocarbon and CO₂ mixtures confined within different nanopores and analysed the diffusion of such fluids and the impact of fluid composition, temperature and mineralogy of the pore. The diffusion of fluids in hydrocarbon reservoirs, especially in tight and shale, largely impact the efficiency of gas injection and recycling processes.⁴

In this work, we calculated the parallel and perpendicular self-diffusion coefficient of mixtures of CO₂ and n-alkanes confined within different minerals important for the oil and gas industry: calcite, silica and kaolinite, each one modelled on an atomistic level. The parallel and perpendicular self-diffusion coefficients of the fluid were computed at the fluid-mineral interface (where high fluid densities are observed due to adsorption) as well as in the middle of the pore, where, depending on the pore height, the effects of the confining media are not so pronounced. From this approach, we observe a very low diffusivity of CO₂ close to the fluid-mineral interface, corroborating the idea of CO₂ being trapped within the hydrocarbon reservoir pores. Furthermore, the diffusivity of the hydrocarbon that is displaced to the middle of the pore exhibits an increase due to the selective adsorption of CO₂ on the pore surface when compared to a case where no CO₂ is present in the pore.

The second process for enhanced oil and gas recovery investigated in this work is water flooding. In the water flooding process, water streams are injected in the reservoir which cause hydrocarbon displacement, leading to enhanced oil and gas recovery. Water streams with different saline content might be used, and these can as well differ from the content in the water that is already present in the reservoir.⁵ Experimental investigation indicates that brine salinity has an impact on the wettability in different rocks.^6,7 This phenomenon is directly related to the formation of the electrical double layer over the rock, which leads to a fast decay in the electrical potential above the surface. Such a decay reduces the overall polarity of the surface leading to a lower hydrophilicity. We used molecular dynamics simulations to understand the effects of electrolytes in fluids confined in systems relevant to the oil and gas industry. Based on experimental data available for the salt composition of sea, formation and produced water, simulations of a range of ionic strength of brine solutions confined by calcite nanopores were performed. Although the calcite surface is overall neutral, the first layer of ions close to the calcite surface is composed by Na⁺, which is related not only to the strong ionic interactions between sodium and carbonate ions, but also to the positioning/availability of the former. As brine concentration increases, strong overscreening effects are observed along with the reduction of the self-diffusion coefficient of the confined water. For a simple representation of a system where dissolution of calcite is present, different molecular dynamics simulations were performed where local defects were created on the calcite surface by removal of calcium and carbonate ions. In these cases, the calcite surface is charged which lead to strong overscreening effects being observed even at lower brine concentrations.

The analysis performed up to now paints a clear picture of the relevant conditions of CO₂ and water (re)injection that contribute to enhancing oil and gas recovery and of the underlying mechanisms involved in such processes. Further analysis of complex mixtures of brine, hydrocarbons and CO₂ confined within different minerals is underway, and aims to provide a more realistic description of the conditions present in oil and gas reservoirs.

References

1. Kuuskraa, V. A., Godec, M. L. & Dipietro, P. CO2 utilization from ‘next generation’ CO2 enhanced oil recovery technology. Energy Procedia 37, 6854–6866 (2013).
2. Santos, M. S., Franco, L. F. M., Castier, M. & Economou, I. G. Molecular dynamics simulation of n-alkanes and CO2 confined by calcite nanopores. Energy & Fuels acs.energyfuels.7b02451 (2018). doi:10.1021/acs.energyfuels.7b02451
3. Eliebid, M., Mahmoud, M., Shawabkeh, R., Elkatatny, S. & Hussein, I. A. Effect of CO2 adsorption on enhanced natural gas recovery and sequestration in carbonate reservoirs. J. Nat. Gas Sci. Eng. 1–10 (2017). doi:10.1016/j.jngse.2017.04.019
4. Hoteit, H. & Firoozabadi, A. Numerical Modeling of Diffusion in Fractured Media for Gas Injection and Recycling Schemes. SPE Annu. Tech. Conf. Exhib. 323–337 (2006). doi:10.2118/103292-MS
5. Puntervold, T., Strand, S. & Austad, T. Coinjection of seawater and produced water to improve oil recovery from fractured north sea chalk oil reservoirs. Energy and Fuels 23, 2527–2536 (2009).
6. Iglauer, S. CO 2 –Water–Rock Wettability: Variability, Influencing Factors, and Implications for CO 2 Geostorage. Acc. Chem. Res. 50, 1134–1142 (2017).
7. Liu, N., Bond, G. M., Abel, A., McPherson, B. J. & Stringer, J. Biomimetic sequestration of CO2 in carbonate form: Role of produced waters and other brines. Fuel Process. Technol. 86, 1615–1625 (2005).