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Carbon Dioxide Sequestration and Enhanced Recovery Techniques

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Fluid Injection in Deformable Geological Formations

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Abstract

Selection of sites appropriate to sequester carbon dioxide should identify the source (production) sites, the transport vehicles, and the fate of the injected CO\(_{2}\). The ensuing alterations of the mechanical properties of the reservoir, the magnitude of the subsidence/heave, and the induced microseismicity are key issues to be scrutinized for both safety considerations and public acceptance. This chapter is devoted to modeling aspects of carbon dioxide sequestration. It capitalizes on the overview of the current deployment of pilot tests of Chap. 1 and on the analysis of the thermophysical properties of water and carbon dioxide reported in Chap. 4. Emphasis is laid on the solubility properties of carbon dioxide in water and aqueous solutions, on mutual solubilities in the absence and presence of methane and on the ensuing chemo-mechanical couplings with the rock formation in actual reservoirs. Crack closing and reopening due to salt crystallization (a small scale issue) and the sealing capacity of the caprock (a macroscopic issue) are relevant subjects for the storage in deep sedimentary basins. Wettability, capillary pressures, relative permeabilities, and stability of gas sequestration in saline aquifers and coal seams are addressed. Gas replacement techniques aimed at sequestration of carbon dioxide while enhancing the recovery of oil or gas are overviewed.

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Notes

  1. 1.

    In an ideal mixture, the molar properties of a constituent are equal to the corresponding molar properties of this constituent at the temperature of the mixture but at its partial pressure in the mixture. Refer to Smith et al. (1996), p. 329 et seq, for details.

  2. 2.

    The carbon dioxide molecule O=C=O is endowed with a covalent double bond between the carbon atom C and the two oxygen atoms O.

  3. 3.

    Here are approximations of a few bond energies in kJ/mole. van der Waals interaction: 2–4 per atom pair; hydrogen bond: 4-40; bond C-O: 358; covalent bond: 400; hydrocarbon bond C-H: 413; bond H-O: 424, bond HO-H: 493, covalent hydroxyl bond O-H: 460; bond C=O: 804.

  4. 4.

    The activity coefficient is the ratio of the actual fugacity and of the (Lewis/Randall) fugacity of an ideal mixture.

  5. 5.

    The consideration of CO\(_{2}\)-H\(_{2}\)O-NaCl fluid inclusions which homogenize at temperatures larger than 573 K requires the model to be refined in the appropriate range of temperature, e.g. Mao et al. (2013).

  6. 6.

    The van der Waals equation, published in 1873, is noted as the first successful contribution to alleviate the inaccuracies associated with the ideal gas formulation that came to light in particular during measurements of sound speed. It introduces two material constants that are traced to molecular attraction and molar volume. The van der Waals equation of state (EoS) is able to predict the liquid–vapor coexistence; it can represent the constitutive properties of binary mixtures, but it is not very accurate to define the critical properties or phase equilibria. For pure components and binary mixtures, it provides a compressibility factor Z of 0.375 while data for hydrocarbons range from 0.24 to 0.29 (refer to Fig. 4.17 for the water substance). The Redlich–Kwong EoS and Peng–Robinson EoS, published in 1949 and 1976, respectively, improved the critical properties of binary mixtures, e.g. compressibility factor \(Z= 0.375,0.333,0.307\) for the van der Waals, Redlich–Kwong, and Peng–Robinson EoS, respectively. These three models are termed cubic models because the equation for the volume, at given pressure and temperature, is a cubic polynomial. While only the smallest and largest of these roots have a physical meaning, the details of the isotherm described by these cubic polynomials between these two roots are disregarded, and it is admitted that the isotherm should be straight, as sketched in Fig. 4.23. Refer to Smith et al. (1996), p. 80 et seq., for a thorough presentation.

  7. 7.

    The global injection rate for the three wells seems to be from 0.5 to 1 Mt/year \(\sim \) 32 kg/s. An injection rate per unit length of well is given in Lee et al. (2013), also 0.02 kg/m/s, equivalent to 630.72 tons/m/year in Rutqvist et al. (2013).

  8. 8.

    The activity coefficients, between 0 and 1, at low ionic strength are usually obtained via the Debye–Hückel formula \(\mathrm{Ln}\,\gamma _i=-A\,\zeta _i^2\,\sqrt{I}\), where the factor \(A=A(T)\) depends on the solvent and temperature (it is equal to 1.172 (kg/mole)\(^{1/2}\) at 25 \(^{\circ }\)C, Appelo and Postma (1993), p. 50), \(\zeta _i\) is the valence and \(I={\frac{1}{2}} \,\sum \zeta _i^2\,y_{0i}\) the ionic strength (less than 0.02 for fresh water and about 0.7 for seawater), the \(y_{0}\)’s being bulk molalities, i.e. moles of ions per kg of water.

  9. 9.

    Refer to Sect. 7.3.4.3 for a derivation. For further comments and comparison between steady-state and transient methods to measure the permeability of CO\(_{2}\) systems, the reader may refer to, e.g. Müller (2011) or Zhang et al. (2014).

  10. 10.

    According to the so-called Klinkenberg effect, the expression giving the permeability to gas at arbitrary pressures may be extrapolated to yield, at large pressures, the permeability of the substance in its liquid state. The difference of permeabilities is attributed to the slip of the gas over the walls. In explicit form, the ratio of the permeability to gas \(k_g\) [m\(^2\)] and to liquid \(k_\ell \) is equal to \(1+ b/p\) where p [Pa] is the pore pressure and b [Pa] the Klinkenberg slip factor. The latter is equal to \(c\,k_\mathrm{B}\,T/(\sqrt{2}\,\pi \,R^3)\) with c [-] a constant, \(k_\mathrm{B}\) [J/K] the Boltzmann constant, T [K] the temperature, and R [m] the pore radius. Therefore, permeability measurements using gas should take place at large pressure to avoid the Klinkenberg effect. The Klinkenberg slip factor is correlated with the water permeability in an expression of the format \(b=0.15/k_\ell ^{0.37}\) with \(k_\ell \) in m\(^2\) and b in Pa. The constants differ slightly for other fluids. The Klinkenberg effect is significant for permeabilities lower than \(10^{-18}\) m\(^2\). Tanikawa and Shimamoto (2006) present an experimental analysis for sedimentary rocks and attempt an explanation of the deviation of the gas flow from Darcy’s law (Hagen–Poiseuille flow) based on a visco-plastic Bingham flow.

  11. 11.

    Coal is a sedimentary rock that is found in layers, called beds or seams. It is classified into lignite, bituminous coal, anthracite, corresponding to its maturity, according to its carbon content, percentage of volatiles, and calorific value.

  12. 12.

    Refer to Fig. 2.9 for definitions.

  13. 13.

    At ambient temperature, the solubility of nitrogen N\(_{2}\) in water is about 50 times less than that of CO\(_{2}\), IAPWS (2004). The critical temperature and pressure of nitrogen are, respectively, \(T_c=126.2\) K, \(p_c=3.40\) MPa.

  14. 14.

    As for terminology, absorption denotes a process where molecules are taken up by a fluid while, in an adsorption process, they are taken up by a solid.

  15. 15.

    Nitrogen hydrates float in cold water and in salt water, while carbon dioxide and sulfide hydrates sink in both fluids.

  16. 16.

    The vapor domain/region/zone denotes the part of the gas phase domain with temperature lower than critical.

  17. 17.

    https://www.energy.gov/fe/science-innovation/oil-gas-research/enhanced-oil-recovery (last visit April 07, 2018).

  18. 18.

    This section taps on the chapter 5 of the PhD thesis of my former student M. Abuaisha.

  19. 19.

    Density differences result from CO\(_{2}\) large thermal expansion coefficient; compare Figs. 4.3 and 4.25.

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  1. Institut National Polytechnique, Université de Grenoble, Saint-Martin-d’Hères, France

    Benjamin Loret

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Loret, B. (2019). Carbon Dioxide Sequestration and Enhanced Recovery Techniques. In: Fluid Injection in Deformable Geological Formations. Springer, Cham. https://doi.org/10.1007/978-3-319-94217-9_9

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