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Abstract: Scaling of Co-Current and Counter-Current Capillary Imbibition for Surfactant and Polymer Injection in Naturally Fractured Reservoirs


To increase the capillary imbibition recovery rate and to deplete the matrix oil efficiently, surfactant and polymer solutions can be injected into naturally fractured reservoirs (NFR). Laboratory experiments are needed to understand the response of the reservoir rock and fluids to these applications and a scale-up process is required to quantify the recovery for reservoir conditions before injecting these expensive fluids.This study tests the existing capillary imbibition scaling-up formulations in literature and proposes modifications to them for surfactant and polymer injection applications. Laboratory tests were performed using 500 mD Berea Sandstone cores of different shapes and sizes with different boundary conditions. The rock samples was surface-coated to create many different boundary conditions causing co or counter-current imbibition or both. Kerosene, engine oil, mineral oil and crude oil were selected as the oleic phase. Brine and two different concentrations of surfactant and polymer solutions were used as the aqueous phase. The capillary imbibition recovery curves were then used to test the existing scaling formulations. Modifications were introduced considering the matrix boundary conditions, oil viscosity and wettability and were done either on the Mattax and KyteAs scaling group or by combining this group with other scaling group for the recovery by gravity segregation. In case of counter current flow, gravity force becomes also effective for low IFT case and modification for surfactant injection is required. For different matrix boundary conditions, aqueous solution properties, oil viscosities and IFTs, applicable scaling formulations were defined for performance estimation of surfactant and polymer solution injection into NFR. Considering the situations that the wettability, oil viscosity and IFT at reservoir conditions may not be created at laboratory conditions, the scaling equations were modified to provide an up-scaling of not only the matrix size but also these properties.

 ©Copyright 2000 American Association of Petroleum Geologists. All rights reserved.


AAPG Search and Discovery Article #90911©2000 AAPG Pacific Section and Western Region Society of Petroleum Engineers, Long Beach, California