Assessment of enhanced oil recovery by osmotic pressure in unconventional reservoirs: Application to Niobrara chalk and Codell sandstone

Abstract The ultimate oil recovery from liquid-rich unconventional reservoirs is less than ten percent, thus a great interest in developing enhanced oil recovery (EOR) methods that can increase oil production from such reservoirs economically. Classical waterflooding in unconventional reservoirs is not plausible because of the small pore sizes and low permeability of shale reservoirs. However, when low-salinity water enters the stimulated reservoir micro-fractures an osmotic pressure gradient forms because of the salinity contrast between fracture and matrix and the nanometer size of pore throats (nano- and micro-fractures are a consequence of rock deformation instigated by hydraulic fracturing in shale reservoirs). Even in oil-wet shale reservoirs, osmotic pressure prevails—leading to brine imbibition into the matrix and generating a counter-current flow of oil from the matrix into the fractures. We also recognize that a fraction of the imbibition into the cores is due to capillary pressure while much of the imbibition results from capillary osmosis. In summary, we present a novel method to measure osmotic pressure in core samples. The method was applied to cores from Niobrara and Codell formations in the DJ basin. The osmotic pressure leads to EOR in laboratory cores and could impact EOR in shale reservoirs because of the large volume of low-salinity ‘slickwater’ fracturing fluid used for well completion. In the experiments, we used solvent-extracted clean cores, KCl brine (40,000 ppm), decane, an imbibition cell, and a high-speed centrifuge. It is important to know that we chose and used a pure hydrocarbon component (decane) for the oil, and a simple brine (KCl) for the water in our experiments so the increased low-salinity brine’s larger imbibition magnitude would not be attributed to the wettability alteration as shown by Haagh et al. [11]. For wettability alteration to take place, the oil should contain asphaltenes and some acidic components. Also, brine should contain divalent calcium, magnesium, and other specific ions which are beyond the scope of this study. Osmotic pressures, measured in low permeability shale cores, plus a precise thermodynamic calculation of the activity coefficients enabled us to calculate the ‘membrane efficiency’ of the cores. In our experiments, we used a high-speed centrifuge, first to saturate the cores with formation brine; second, we injected oil into the core to displace brine (1st drainage cycle); third, we allowed spontaneous imbibition of brine into the core; fourth, we conducted force imbibition displacement of the oil with brine until core reaches residual oil saturation. Because osmotic pressure is the difference between the high-salinity and low-salinity spontaneous imbibition capillary pressures, the experimental process was repeated using low-salinity brine. Lastly, we determined the produced oil during low-salinity experiments as a measure of the EOR. Finally, osmotic pressures measured in the low permeability shale cores, plus the calculated activity coefficients, enabled us to calculate ‘membrane efficiency’ of the cores. For the Codell sandstone, with permeability of 0.0085 to 0.0105 mD, the calculated membrane efficiency was 2.4%. Similarly, for the Niobrara B-chalk, with permeability of 0.0022 to 0.0099 mD, the membrane efficiency was 74.9%. This high recovery is attributed to the pore structure of Niobrara chalk vs. that of Codell sandstone.