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Based on the currently discussed ability of HPAM-polymer to increase displacement efficiency due to viscoelastic properties, a comprehensive evaluation of the possible impact on the design of polymer-surfactant mixtures is presented in this investigation. This assessment includes a comprehensive analysis of laboratory experiments. Experimental data was obtained from different sources and furthermore crosschecked, such as: rheological characterization, flooding through microfluidics devices, and core flooding experiments. First, solutions were characterized by the analysis of different rheological techniques. Second, flooding experiments were performed in a microfluidic device which has a hyperbolical contraction-expansion geometry, capable to provide apparent extensional viscosity. Third, single phase core flooding experiment was conducted using Bentheimer core plugs to evaluate the flow behavior of polymer and surfactant in porous media. Finally, flow paths of polymer-surfactant mixtures were described using streamline visualization techniques. The latter was performed injecting the solutions at different flow rates in a Glass-Silicon-Glass (GSG) micromodel generated from a micro CT scan images of a real porous media. Polymer-surfactant mixtures depicted a pseudoplastic behavior with an increasing in polymer's apparent viscosity due to the presence of a surfactant. Polymer extensional viscosity has been slightly improved due to the addition of Polyethylene oxide (PEO) at 0.5wt% and 1.5wt% using a solvent of 4.0 g/l TDS. Increasing in the measured extensional pressure drops suggested that the viscoelastic properties are improved by using polymer-surfactant combination at apparent rates below 720s-1. Shear rate coefficients resulted in an acceptable match between the rheometer and the core flooding measurements. At a critical value of adjusted shear rates (40-50 S-1), viscosity of three solutions was almost the same value of 30 mPa.S (Critical apparent viscosity). After this critical value, HPAM with no PEO and with 0.5wt% PEO showed shear thickening behavior, while with 1.5wt% PEO showed shear thinning behavior till shear rate value of 95 S-1, after this rate, it was dominated by shear thickening behavior. Moreover, different flow regimes were observed through the streamline visualization in GSG micromodels; a zone mainly considered by laminar flow in case of HPAM with 0.5wt% PEO, remarkable vortex was observed in an open pore geometry and crossing streamlines especially in the wall areas in case of HPAM with no PEO. This evaluation leads to understanding the viscoelastic behavior in porous media when polymer and surfactant flooding are applied in combination and provide a proper understanding to complement the few literature resources available about this topic.

Predicting and assuring well deliverability is often an important concern during the development of gas-condensate reservoirs, especially offshore fields. In addition, production of gas is usually bound with long-term contracts where it is necessary to assure well deliverability for a long period. Undesirably, well deliverability in gas-condensate reservoirs can be impaired by the formation of a condensate blockage once the bottomhole flowing pressure drops below the dewpoint pressure. In this case, the relative permeability of the gas phase can be significantly reduced due to this condensate accumulation around the wellbore. Therefore, quantifying this negative effect is essentially required to obtain reliable predictions of well deliverability in gas-condensate reservoirs. The evaluation of condensate blockage phenomenon requires an appropriate understanding of flow characteristics of both gas and condensate liquid through reservoir rocks. In this study, the impact of condensate blockage on gas well deliverability was investigated by examining a number of flow parameters such as absolute permeability (K), critical condensate saturation (Scc), relative permeability shape and end-points (krgmax, kromax). A single well radial and cartesian models were both used in different simulators (modified black-oil and compositional). The outcomes of this study showed that the condensate blockage can have a severe negative impact at low permeability reservoirs (K≈5md), while the impact can be small at moderate permeability (k≈50md) and diminishable at high permeability reservoirs (k≈200md). This negative impact can double at high critical condensate saturation (Scc>30%). It was found out that the relative permeability curves applied in the model define the magnitude of the blockage, especially in low permeability reservoirs, whereas relative permeability end-points (krgmax and kromax) affect mainly the overall gas recovery. Previous lab measurements showed that gas-condensate relative permeabilities are sensitive to flow velocity only in low permeability reservoirs. This effect was modeled using a compositional model through the capillary number. Velocity-dependent relative permeability model applied in this case showed that the plateau period can be improved by a factor of two in low permeability. On the other hand, no positive effect was observed at moderate and high permeability since the blockage effect was already small or dimensionless. Finally, the benefit of methanol injection was investigated for improving well deliverability at low permeability reservoirs. Based on this analysis, methanol treatment can improve gas well deliverability and substantially prolong the plateau period by a factor of 2-3.

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The potential of CEOR application in mature oil fields can be investigated using sector models of an appropriate boundary conditions. In this paper, we present an evaluation of feasibility study of surfactant and estimation of the incremental recoverable oil in a mature Libyan oil field assuming the availability of surfactant formulation with optimal performance at reservoir conditions. Overall permeability of reservoir rock is rather low which limits the applicable areas of CEOR applications. Reservoir properties were characterized using an established optimization approach to define pilot areas that exhibit favorable conditions for chemical EOR flooding. An intensive study was accomplished to generate a sector model of an optimum boundary conditions that provide pronounced results to the Full Field Model (FFM). Typical laboratory data were used to design surfactant model at an ultra-low interfacial tension (IFT) of 10−3 mN/m. Furthermore, main parameters that could influence the results of surfactant model were optimized: flow rates, residual oil saturation (Sorc), correlated Capillary De-Saturation Curve (CDC), adsorption, and grid size effect. Interstitial velocity of displacing fluid and capillary number were correlated to describe the effect of permeability variation on the ultimate residual oil saturation. Additional recovery by surfactant at current reservoir conditions appeared to be strongly affected by changing the correlated CDC. The estimated macroscopic efficiency of surfactant by the coarse and fine grid models indicates that the surfactant is being smeared in the coarse model, and consequently different pressure distribution in both models was observed after certain time of injection. Moreover, the predicted results illustrate the influence of any heterogeneity feature in reservoir properties on both microscopic (ED) and macroscopic (EV) sweep efficiencies of CEOR flooding. In Addition to the lessons learned of proper simulation at field scale, a developed approach to evaluate the potential of CEOR at challenging reservoir conditions is introduced in this paper.