In this paper an innovative structure/property approach is used to evaluate several commercially available surfactants in tests relevant to both alkaline-surfactant-polymer (ASP) and surfactant-polymer (SP) floods, in order to gain an understanding of how hydrophobe structure is related to surfactant performance and crude oil composition. The surfactant structural elements considered here include relative branching level and carbon chain length. This has application to chemical EOR implementation in fields over a range of reservoir temperatures and salinity. Phase behavior (giving interfacial tension), and micro-emulsion viscosity tests were carried out for internal olefin sulfonates and mixtures with alcohol propoxy sulfates to identify those that perform well while minimizing or eliminating the use of costly co-solvents. Hydrophobe branching and carbon chain length, characterized by gas chromatography, were used to match surfactants to certain crude oil properties such as natural surfactants, including total acid number (TAN) and asphaltenes, and the ratio of saturates/aromatics. The paper also examines how crude oil sampling influences crude properties and surfactant performance. The approach used and associated data contribute to cost reduction of formulations through a) better matching of commercially produced surfactants to the reservoir and crude oil properties to improve oil recovery efficiency, and b) minimizing or eliminating the use of co-solvents to reduce formulation and logistics costs. In addition, the study demonstrates how binary blends from a few core surfactants can match formulations across regionally different crude oils thereby simplifying formulation selection, and reducing uncertainty and cost.

ASP flooding achieves high incremental oil recovery factors over water flooding by reducing the interfacial tension (IFT) to ultralow values and by ensuring good mobility control, provided by the polymer. Traditionally, this has been achieved by tuning the ASP flood so that it is at optimum salinity conditions, i.e. Winsor type III micro-emulsion phase. Systematic studies of the performance of ASP at different (non-optimum) salinities are scarce, while operating at lower salinities condition can offer several advantages. These include: (1) lower surfactant retention and (2) increased polymer viscosifying power, enabling a reduction in required chemical volumes, as well as (3) a lower risk of achieving over-optimum salinity conditions in the field. This paper presents a series of core-flood experiments using light crude oil with a low Total Acid Number (TAN) and two different sandstone rock types (Bentheimer and Berea). Injection salinities ranged from under-optimum to optimum conditions (i.e. giving type II- to type III micro-emulsion systems), supported by phase behaviour and spinning drop IFT measurements. The formulation used was a model, non-optimized one with one internal olefin sulfonate (IOS) surfactant component. The injected ASP solution showed no phase separation but it was not clear. Results for this IOS surfactant system, without the addition of extra components such as a co-surfactant for improved aqueous solubility, show that ASP core flood tests performed at different salinities, both at optimum salinity and up to 1.5% NaCl under-optimum, recovered similar amounts of oil remaining in the core after water flooding, regardless of a factor three difference in IFT within the range of 10−3 and 10−2 mN/m. The residual oil saturation after chemical flooding (Sorc) was similar amongst the different experiments, ranging from 16% up to 19% Pore Volume (PV) for our specific model formulation. Moreover, oil and chemical breakthrough times are in the same range for all experiments: around 0.5 PV and 1 PV, respectively. Although total oil recovery was not affected by flooding at under-optimum conditions, lower surfactant retention and a higher oil recovery before chemical breakthrough (i.e. as clean oil) were found. In the absence of a surfactant (AP flood), poor recovery of residual oil after water flooding, regardless of a factor three difference in IFT within the range of 10−3 and 10−2 mN/m. The residual oil saturation after chemical flooding (Sorc) was similar amongst the different experiments, from 16% up to 19% Pore Volume (PV) for our specific model formulation. Moreover, oil and chemical breakthrough times are in the same range for all experiments: around 0.5 PV and 1 PV, respectively. Although total oil recovery was not affected by flooding at under-optimum conditions, lower surfactant retention and a higher oil recovery before chemical breakthrough (i.e. as clean oil) were found. In the absence of a surfactant (AP flood), poor recovery of residual oil after water flood was achieved (Sorc 32% PV). These findings suggest that injection at under-optimum conditions may be, for an IOS surfactant system, an improved, alternative to injecting at optimum conditions. Further work is recommended to quantify its advantages, including with more aqueous soluble optimized surfactant systems.