ASP Processes: Wide Range of Conditions for Good Recovery

Abstract

Design of an alkaline-surfactant-polymer (ASP) process requires knowledge of the amount of soap formed under alkaline conditions from naphthenic acids in the crude oil. We show here for several crude oils that the acid number determined by nonaqueous phase titration is approximately twice that found by hyamine titration of a highly alkaline aqueous phase used to extract soaps from the crude oil. This acid number by soap extraction should provide a better estimate than nonaqueous phase titration. This soap interacts with the injected surfactant to form surfactant films and microemulsion droplets during an ASP process. In a previous paper (Liu et al., 2006), an unusually wide range of salinities of ultra-low oil-water interfacial tensions (IFTs) was found for one alcohol-free crude oil/anionic surfactant system under alkaline conditions where naphthenic soaps were present. This surprising and favorable behavior has now been found to exist with the same surfactant blend and another crude oil. In the same paper, a one-dimensional simulator for the ASP process was presented. Here this ASP simulator has been used for various acid contents, injected surfactant concentrations, slug sizes and salinities to show that high recoveries of waterflood residual oil (>90%) can be expected for a wide range of near-optimal (Winsor III) and under-optimum (Winsor I) conditions for a constant salinity process, even with relatively small slug sizes. A key factor leading to this good performance is development of a gradient in soap-to-surfactant ratio, which assures that a displacement front with ultralow IFT forms and propagates through the formation. Similar high recoveries can be attained for certain over-optimum (Winsor II) conditions but only for much larger slug sizes owing to the tendency for surfactant to partition into the oil phase and become retarded. Large dispersion such as might be expected for field conditions can significantly reduce recovery for small surfactant slugs even for near-optimal and under-optimum conditions. However, this problem can be overcome by injecting the slug and/or drive at salinities below reservoir salinity, thereby creating a salinity gradient. Introduction Alkaline-surfactant processes offer considerable promise for enhanced oil recovery (EOR). The alkali converts naphthenic acids in the crude oil to soaps. The combination of the soaps and a suitably chosen injected surfactant reduces interfacial tensions to ultralow values, where residual oil can be mobilized and oil trapping prevented. As discussed more fully in a previous paper (Liu et al, 2006), the alkali reduces surfactant adsorption. Soaps are usually too lipophilic to produce ultralow tensions at reservoir conditions. Effective, hydrophilic, injected surfactants can be injected in an alkaline-surfactant process at salinities below their optimal salinities for oil recovery when used in the absence of alkali (Nelson, et al., 1984). The result is to further reduce adsorption and to facilitate finding surfactant slug compositions where addition of polymer to provide adequate mobility control does not cause undesirable separation into polymer-rich and surfactant-rich phases. The drive is also a polymer solution, so that the process is of the alkaline-surfactant-polymer (ASP) type. Liu et al (2006) presented phase behavior, interfacial tensions (IFTs), adsorption isotherms, and results of ASP experiments in silica and dolomite sand packs for a system with a particular surfactant blend (NI blend) and a West Texas crude oil (Yates). The alkali was sodium carbonate, and all experiments were conducted at ambient temperature. A mixture of a propoxylated sulfate and an internal olefin sulfonate, the NI blend was used with no added alcohol or other cosolvent. It was a single-phase micellar solution for salinities up to approximately its optimal salinity with the crude when minimal soap is present, making it suitable for injection at lower salinities in an ASP process, as mentioned above.

Foam Mobility Control for Surfactant Enhanced Oil Recovery

“…This formulation reduced oil/water IFT to the order of 10 −3 mN/m and had displaced oil successfully in previous ASP sandpack experiments (Liu et al 2008b). Simulations indicate that high recovery is possible for a wide range of conditions with injection below optimal salinity of the surfactant owing to development of a gradient in soap fraction (Liu et al 2008a).…”

“…The optimal salinities for the three crude oils and NI blend are shown in Fig. 2 as a function of the fraction soap/(soap+surfactant), with soap content based on the amount of soap extracted from the crude oil for highly alkaline conditions as measured by aqueous-phase titration (Liu et al 2008a). Arrows in this fi gure show the values of the soap fraction determined from the water/oil ratio corresponding to waterfl ood residual-oil saturation.…”

Recent Advances in Surfactant EOR

“…13 shows that the soap content by such aqueous extraction is about one-half of the TAN, which is measured by nonaqueous titration. Apparently about one-half of the TAN content is too hydrophobic to be extracted into the aqueous phase (e.g., asphaltene) and/or is too hydrophilic to be detected by hyamine titration (Liu, et al, 2008b). The Salager, et al (1979) mixing rule was found to be followed reasonably well when the aqueous titration method was used to quantify the soap content of the crude oil, Fig.…”

“…If sodium naphthenate is to act as a surfactant, it should partition into the aqueous phase at low electrolyte concentrations and be measurable by hyamine titration for anionic surfactants. It was found (see later) that the sodium naphthenate determined by extraction into the aqueous phase and measured by hyamine titration is about one-half of the TAN value (Liu, et al, 2008b). It is hypothesized that the TAN includes components that are too lipophilic to be extracted to the aqueous phase and/or too hydrophilic to be detected by hyamine titration.…”

“…The IFT estimated from the Huh correlation shows this crude oil to also have a wider, ultra-low IFT region of salinities, especially in the underoptimum region. (Liu, et al, 2008b).…”