Premium
Estimation of Capillary Pressure in Unconventional Reservoirs Using Thermodynamic Analysis of Pore Images
Author(s) -
Anbari Alimohammad,
Lowry Evan,
Piri Mohammad
Publication year - 2019
Publication title -
journal of geophysical research: solid earth
Language(s) - English
Resource type - Journals
SCImago Journal Rank - 1.983
H-Index - 232
eISSN - 2169-9356
pISSN - 2169-9313
DOI - 10.1029/2018jb016498
Subject(s) - capillary pressure , capillary action , saturation (graph theory) , relative permeability , oil shale , geology , imbibition , fluid dynamics , pore water pressure , wetting , reservoir simulation , mechanics , petroleum engineering , mineralogy , materials science , geotechnical engineering , porous medium , porosity , composite material , mathematics , paleontology , germination , botany , physics , combinatorics , biology
Unconventional reservoirs comprise a growing portion of producible reserves due to increasing knowledge of their nature as well as significant advances in production technology. The development of advanced pore‐scale modeling techniques presents potential for better estimation of reservoir flow characteristics including relative permeability, saturation distributions, and capillary pressure. Although pore‐scale network models take into account the pore throat connections and the appropriate fluid properties, highly simplified pore cross‐sectional shapes are still employed when estimating the threshold capillary pressure for fluid‐fluid displacements in each pore element. As a result, there is a growing need for more realistic threshold capillary pressure estimates generated using pore geometries that honor the real pore topology. To this end, a semianalytical model is presented that allows the prediction of threshold capillary pressure as well as the capillary pressure versus saturation relationship for piston‐like fluid displacements using images of unconventional reservoir rock samples. The model was validated on three different idealized pore geometries and compared against available analytical solutions, resulting in an error of less than 1% for all cases. The model was compared to experimental data using fluid occupancy maps obtained using an X‐ray nano‐CT scanner during an oil imbibition sequence into a miniature reservoir shale sample. The capillary pressure versus wetting phase saturation relationship was also determined for a 2‐D focused ion beam scanning electron microscopy image slice. The presented model shows promise for enabling more advanced pore‐scale modeling of shale rock.