Issue 49

A. Kostina et alii, Frattura ed Integrità Strutturale, 49 (2019) 302-313; DOI: 10.3221/IGF-ESIS.49.30 312 scenario corresponds to the case of the pore compression while the second one describes increase in porosity induced by the volumetric strains. The following conclusions can be made:  Operational parameters p b =3.6 MPa, T b =220 K substantially accelerate steam propagation within the reservoir compared to the values p b =2.5 MPa, T b =213 K.  The oil production rate strongly depends on the prevailing physical mechanism of the porosity evolution. Pore compression impairs oil production. The operational parameters p b =2.5 MPa, T b =213 K give almost threefold smaller oil production rate for both porosity models.  The considered values of operational parameters do not induce caprock failure if plastic strains in the reservoir is taking into account. Therefore, neglecting of the inelastic strains leads to the overestimation of the caprock strength even for the small values of the operational parameters. A CKNOWLEDGMENTS his work was supported by the grant of the President of Russian Federation for support of young Russian scientists and leading scientific schools [MK-4174.2018.1]. R EFERENCES [1] Shafiei, A., Dusseault, M. B. (2013). Geomechanics of thermal viscous oil production in sandstones, J. Pet. Sci. Eng., 103, pp. 121–139. DOI: 10.1016/j.petrol.2013.02.001 [2] Uribe-Patino, J.A., Alzate-Espinosa, G.A., Arbelaez-Londono, A. (2017). Geomechanical aspects of reservoir thermal alteration: A literature review, J. Pet. Sci. Eng., 152, pp. 250-266. DOI: 10.1016/j.petrol.2017.03.012. [3] Yin, Y., Li, Y. (2015). FEM analysis of fluid-structure interaction in thermal heavy oil recovery operations, Sustainability, 7, pp. 4035-4048. [4] Lin, B., Chen, S., Jin, Y. (2017). Evaluation of reservoir deformation induced by water injection in SAGD wells considering formation anisotropy, heterogeneity and thermal effect, J. Pet. Sci. Eng., 157, pp. 767-779. [5] Pao, W. K. S., Lewis, R. W., Masters, I. (2001). A fully coupled hydro ‐ thermo ‐ poro ‐ mechanical model for .black oil reservoir simulation, Int. J. Numer. Anal. Meth. Geomech., 25 (12), pp. 1229-1256. DOI: 10.1002/nag.174 [6] Chen, W., Tan, X., Yu, H., Wu, G., Jia, S. (2009). A fully coupled thermo-hydro-mechanical model for unsaturated porous media, J. Rock Mech. Geotech. Eng., 1, pp. 31–40. DOI: 10.3724/SP.J.1235.2009.00031. [7] Zandi, S., Renard, G., Nauroy, J.-F., Guy, N., Tijani, M. (2010). Numerical coupling of geomechanics and fluid flow during steam injection in SAGD, SPE improved oil recovery symposium, 24-28 April, Tulsa, USA, SPE-129739-MS. DOI: 10.2523/129739-ms. [8] Settari, A. (1992). Physics and modeling of thermal flow and soil mechanics in unconsolidated porous media, SPE Production Engineering, 7(1), pp. 47-55. DOI: 10.2118/18420-PA. [9] Zimmerman, R. W., Somerton W. H., King M. S. (1986). Compressibility of porous rocks, J. Geophys. Res.-Sol. Ea., 91, pp. 12765-12777. DOI: 10.1029/JB091iB12p12765. [10] Osorio, J. G., Chen, H-Y., Teufel, L.W. (1997). Numerical simulation of coupled fluid-flow/geomechanical behavior of tight gas reservoirs with stress sensitive permeability, Latin American and Caribbean Petroleum Engineering Conference, 30 August - 3 September, Rio de Janeiro, SPE-39055-MS. DOI: 10.2118/39055-MS. [11] McKee, C. R., Bumb, A. C., Koenig, R. A. (1988). Stress-dependent permeability and porosity of coal and other geologic formations, SPE Formation Evaluation, 3(1), pp. 81-91. DOI: 10.2118/12858-PA. [12] Rutqvist, J., Wu, Y.-S., Tsang, C.-F., Bodvarsson, G. A. (2002). Modeling approach for analysis of coupled multiphase fluid flow, heat transfer, and deformation in fractured porous rock, Int. J. Rock Mech. Min. Sci., 39(4), pp. 429-442. DOI: 10.1016/S1365-1609(02)00022-9. [13] Wang Y., Dusseault M. B. (1991). The effect of quadratic gradient terms on the borehole solution in poroelastic media, Water Resour. Res., 27 (12), pp. 3215-3223. DOI: 10.1029/91WR01552. T