Design of Surfactant-Only Chemical Flooding in a Low Perm, High Tds Reservoir: Single Well Test

Low permeable oil reservoirs are often characterized by slow waterflood injectivity and low fluid productivity. For low perm formations, the permeability appears to be the limiting factor to deploy Surfactant-Polymer (SP) and Alkaline Surfactant Polymer (ASP) flooding for improved oil recovery. Injection of carbon dioxide has shown promising results in low perm formations and is commonly used in these fields when sufficient CO₂ can be obtained. However, even when sufficient CO₂ can be sourced, initial capital investments for CO₂ injection may be quite high and may limit its application for some mature fields.  In this paper we report a single-well test of an improved surfactant-only formulation in a low permeability, high TDS reservoir. The target single well, SEH1, is located in south central of Oklahoma. The perforated zone is located 6,000 feet below the surface with an on-going waterflood. The average permeability of the formation is 14 mD, ranging from 0.2 to 44 mD. The produced brine contains total dissolved solids (TDS) at 102,300 mg/L and the reservoir temperature is 50 °C (123 °F). The reservoir crude exhibits a viscosity of 23 cp at reservoir conditions, presenting further challenges for an EOR process without mobility control using polymer. For the test, the hydrophilic-lipophilic difference (HLD) equation was used to predict possible salt-tolerant surfactant formulations, based on site-specific fluid properties and reservoir conditions. Among the binary and ternary surfactant mixtures developed, the surfactant formulations were further optimized by introducing low concentrations (between 400 to 600 mg/L) of hydrophilic linkers  to achieve a stable surfactant solution in the reservoir brine and ultra-low interfacial tensions (< 0.008 mN/m) between site crude and produced brine. In laboratory testing injection of three pore volumes of a surfactant-only formulation in sand packs and core flood devices achieved tertiary oil recovery ranging from 45% to 70% of the residual oil (Sor) after water flooding. The levels of surfactant loading were varied from 0.23 wt% to 0.92 wt% to assess the impact of surfactant concentration along with slug size.  The field single well test used a ternary surfactant formulation (i.e., a mixture of alkoxylated alcohol sulfates/ethoxylated alcohol sulfates/blends of monoalkyl and dialkyl diphenyloxide disulfonates) and was conducted in April-May of 2013 to further confirm laboratory results at the SEH1 site. The 3-week single-well test was a technical success. A surfactant only formulation was injected at 0.69% followed by injection of reservoir brine without mobility control.  Based on the pre- and post-chemical tracer test results (i.e., use of ethyl formate as partitioning tracer plus other conservative tracers), approximately 90% of the residual oil at the target zone was mobilized.  This field experience will be built into a design protocol using single-well tests to mitigate the risks of pilot-scale chemical flooding targeted at mature fields in the U.S. mid-continent region.