Aqueous solutions with polymer additives often used to improve the macroscopic sweep efficiency in oil recovery typically exhibit non-Newtonian rheology. In order to predict the Darcy-scale effective viscosity μ eff required for practical applications often, semiempirical correlations such as the Cannella or Blake-Kozeny correlation are employed. These correlations employ an empirical constant ("C-factor") that varies over three orders of magnitude with explicit dependency on porosity, permeability, fluid rheology and other parameters. The exact reasons for this dependency are not very well understood. The semi-empirical correlations are derived under the assumption that the porous media can be approximated by a capillary bundle for which exact analytical solutions exist. The effective viscosity μ eff (v Darcy ) as a function of flow velocity is then approximated by a cross-sectional average of the local flow field resulting in a linear relationship between shear rate γ and flow velocity. Only with such a linear relationship, the effective viscosity can be expressed as a function of an average flow rate instead of an average shear rate. The local flow field, however, does in general not exhibit such a linear relationship. Particularly for capillary tubes, the velocity is maximum at the center, while the shear rate is maximum at the tube wall indicating that shear rate and flow velocity are rather anti-correlated. The local flow field for a sphere pack is somewhat more compatible with a linear relationship. However, as hydrodynamic flow simulations (using Newtonian fluids for simplicity) performed directly on pore-scale resolved digital images suggest, flow fields for sandstone rock fall between the two limiting cases of capillary tubes and sphere packs and do in general not exhibit a linear relationship between shear rate and flow velocity. This indicates that some of the shortcomings of the semi-empirical correlations originate from the approximation of the shear rate by a linear relationship with the flow velocity which is not very well compatible with flow fields from direct hydrodynamic calculations. The study also indicates that flow fields in 3D rock are not very well represented by capillary tubes.

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Heterogeneities in the reservoir can result in poor sweep efficiency during water and chemical floods. In many cases the sweep efficiency is improved significantly when changing to polymer flood. However, in the presence of very high conductive features polymer by itself may not be sufficient and result in undesired polymer production. Diversion of the flow to oil saturated regions and minimization of polymer production is then desired. In the presence of cross-flow the best option is placing a (chemical) plug deep in the reservoir. Adding a second component to the injection polymer stream that can react with the polymer to form a cross-linked gel is then an effective solution. However controlled placement and triggering of the reaction is very challenging. In this paper we will present the results of static bulk measurements and dynamic core flooding experiments that were performed to identify cross-linked polymer systems. The polymers in the system are the typical high molecular weight partially hydrolyzed polyacrylamide (HPAM) polymers used in polymer flooding projects. The experimental work is focused on understanding and controlling the gelation time to enable proper placement and triggering at any given distance from the injectors. Parameters of investigation included temperature, brine composition, polymer concentration and rock mineralogy. The main parameters affecting the gelation process and possible failure mechanisms were identified. For given conditions, retardation of gelation time varying from few days up to several months could be designed. The learning from the experimental results can be used for improved material selection and design for other chemical and water flooding.

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The volumetric sweep efficiency is an essential factor in the success of any water flooding or EOR project. Volumetric sweep efficiency (VSE) is controlled by the local reservoir geological settings, well patterns and completion design and production and injection strategies. In this paper we present a numerical modeling methodology to quantify VSE for different well patterns and geological settings independent of fluid types and saturation. The impact of conformance control techniques on VSE is estimated and the results translated to ultimate oil recovery for different driving mechanisms through standard analytical approximations. The methodology is used to evaluate the impact of conformance control techniques during water and polymer flooding for medium to high viscous oil reservoir. The results show that unselective blocking of high permeable layers during water flooding of high viscous oil reservoirs can be counterproductive and narrows the scope of potential chemical EOR opportunities. Polymer-(like) flooding wherever applicable is found to be in itself a very efficient conformance technique to increase the overall sweep efficiency for geological heterogeneities. In general abnormal high conductive features and long induced fractures tend to lower the efficiency of water or chemical flooding and cause excessive water/chemicals production to the surface facilities. Near wellbore mechanical treatments are then effective to minimize polymer production and increase oil production of which examples from ongoing polymer project will be discussed.