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Nanoparticles have been widely investigated for their mechanisms in enhanced oil recovery, such as rock wettability alternation, oil displacement by disjoining pressure, and the stabilization of emulsion and foam. Nanogels are nanosized cross-linked polymeric particles that have the properties of both nanoparticles and hydrogels. The goal of this study is to investigate the oil–water interfacial behavior in the presence of nanogels, especially the dynamic interfacial tension and the stability of oil-in-water (o/w) emulsions. The nanogels synthesized in this study are able to reduce the oil–water interfacial tension and stabilize the o/w emulsions. The diameter and ζ potential of the charged nanogels are dramatically influenced by brine salinity, whereas the neutral charged nanogels are barely affected by salt. The synthesized nanogels have been stable in distilled water and brines at room temperature for more than 60 days. The dynamic interfacial tension results show that the nanogels are able to reduce the oil–water interfacial tension to as much as 1/30 of the original value. In addition, the interfacial tension reduction is more significant at a higher salinity (ranging from 10 000 to 50 000 ppm NaCl concentration). The emulsion stability results demonstrated that the stability of emulsified oil drops was controlled by both the strength of the adsorbed nanogel layers and the interactions among oil drops. The core flooding experiments have indicated the residual oil can be fragmented and produced in the o/w emulsion state. In addition, the diameter of emulsified oil drops in effluent is inversely proportional to the shear rate. The salt-dependent interfacial tension and emulsion stability indicated that the appropriate charged nanogel can be a promising candidate for enhanced oil recovery.

Relative permeability is one of the most important petrophysical parameters to evaluate a reservoir’s production during primary and subsequent secondary or enhanced oil recovery processes. Yet measured relative permeability data for tight oil reservoirs are very scarce to find in the literature, mainly because the measurement is difficult and time consuming to make. In this paper the protocol and results of water/oil, surfactant /oil, CO2/oil, and N2/oil relative permeability are presented, and compared to the digital core analysis results where wettability was set to water-wet or mixed-wet, as well as the Brooks-Corey model. Amott-Harvey wettability index was measured to explain the differences. The target formation is a sandstone tight oil formation located in Songliao Basin, China. Its permeability is mostly in the 0.01-5mD range. Core and oil samples from the target formation were used in the wettability and relative permeability determination. Relative permeability was measured at reservoir conditions using a customized core flow setup. Core samples were cleaned then wettability restored. To match the reservoir fluid viscosity and avoid changing wettability, stock tank oil was blended with kerosene to reservoir fluid viscosity at reservoir temperature. Relative permeability was measured using the unsteady-state method. Amott-Harvey wettability index was measured on core samples from the same formation at reservoir temperature. Amott-Harvey wettability index results show that the restored wettability ranged from water-wet to oil-wet, with most samples being mixed-wt. The addition of non-ionic surfactant promoted wettability change toward more water-wetness. However, anionic surfactant had little effect on reversing wettability. Oil relative permeability (Kro) results obtained from the digital rock analysis (DRA) assuming uniform water-wetness are consistent with relative permeability calculated from mercury injection capillary pressure using Brooks-Corey model. When wettability of the digital rock model was set to mixed-wet, the resulted Kro matches the measured Kro of a sister plug to the sample used to build the digital rock model, which is consistent with the wettability measurements. The addition of surfactants increased both water and oil relative permeability through wettability alteration and IFT reduction. CO2 flood was conducted as an immiscible flood due to reservoir pressure lower than MMP. CO2 flood left high residual oil saturation compared with water floods. N2 flood left even more oil behind compared with CO2 flood. Relative permeability provides key input parameters for formation evaluation and the subsequent EOR processes such as huff-n-puff operations. There are very little published relative permeability data for tight oil reservoirs. This work extends the relative permeability database, and is a starting point for future EOR work.

This paper extends the results obtained for one-dimensional Markovian jump systems to investigate the problem of H ∞ model reduction for a class of linear discrete time 2D Markovian jump systems with state delays in Roesser model which is time-varying and mode-independent. The reduced-order model with the same randomly jumping parameters is proposed which can make the error systems stochastically stable with a prescribed H ∞ performance. A sufficient condition in terms of linear matrix inequalities (LMIs) plus matrix inverse constraints are derived for the existence of a solution to the reduced-order model problems. The cone complimentarity linearization (CCL) method is exploited to cast them into nonlinear minimization problems subject to LMI constraints. A numerical example is given to illustrate the design procedures.