Alkaline/Surfactant/Polymer Processes: Wide Range of Conditions for Good Recovery

Abstract

Summary 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, when substantial acid is present, 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 because the extracted soap interacts with the injected surfactant to form surfactant films and microemulsion droplets during an ASP process. In a previous paper (Liu et al. 2008), an unusually wide range of salinities of ultralow oil/water interfacial tensions (IFTs) was found for one alcohol-free crude-oil/anionic-surfactant system under alkaline conditions where naphthenic soaps were present. Solubilization results indicate that this favorable behavior exists with the same surfactant blend and another crude oil. In the same paper, a 1D 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 underoptimum (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/surfactant ratio, which ensures that a displacement front with ultralow IFT forms and propagates through the formation. Similar high recoveries can be attained for certain 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 reduce recovery significantly for small surfactant slugs even for near-optimal and underoptimum conditions. However, this problem can be overcome by injecting the slug or drive at salinities below reservoir salinity, thereby creating a salinity gradient.

Application of nanofluid to control fines migration to improve the performance of low salinity water flooding and alkaline flooding

“…Another technique to unlock the residual oil which has been gained very considerable attention is alkaline/caustic flooding (French and Burchfield, 1990;Liu et al, 2010;Stoll et al, 2011). In this technique alkali can be utilized (1) as a pre-flush slug (2) in conjunction with polymer and surfactants (3) as a major recovery agent.…”

“…In this process, polymer is added to the water as a viscosifying agent to improve sweep efficiency and prevent fingering during water injection into the reservoir (Garmeh et al, 2012;Hild and Wackowski, 1999;Kazempour et al, 2012;Lei et al, 2011;Perez et al, 2012;Seright et al, 2009;Urbissinova et al, 2010); however, the early adsorption/loss of polymer on the rock surface can deteriorate the cost-efficiency of the process. This challenge seems to be handled by the effect of alkali utilized in AP injection and ASP flood, which results to mitigate the adsorption/loss of the expensive polymer and/or surfactant which in turn makes the process more cost-effective (Flaaten et al, 2010;French and Burchfield, 1990;Kazempour et al, 2012;Liu et al, 2008;Liu et al, 2010;Stoll et al, 2011). Furthermore, the alkali injected as a principal recovery agent can react with the oil to form in-situ generated natural surfactant named as petroleum soap which can reduce the interfacial tension and in turn unlock the trapped oil (Liu et al, 2010;Stoll et al, 2011).…”

“…This challenge seems to be handled by the effect of alkali utilized in AP injection and ASP flood, which results to mitigate the adsorption/loss of the expensive polymer and/or surfactant which in turn makes the process more cost-effective (Flaaten et al, 2010;French and Burchfield, 1990;Kazempour et al, 2012;Liu et al, 2008;Liu et al, 2010;Stoll et al, 2011). Furthermore, the alkali injected as a principal recovery agent can react with the oil to form in-situ generated natural surfactant named as petroleum soap which can reduce the interfacial tension and in turn unlock the trapped oil (Liu et al, 2010;Stoll et al, 2011).…”

An experimental and numerical study of chemically enhanced water alternating gas injection

“…A high oil and water solubilization ratio at optimal salinity is correlated with an ultralow IFT, which is the key mechanism in surfactant-based chemical EOR. The details of this method are well established (Flaaten et al 2009;Liu et al 2010;Levitt et al 2011). Determining the IFT value at optimal salinity is very important in surfactant selection and performance.…”

Numerical studies on the effects of various complicated barrier configurations on sweep efficiency in surfactant/polymer flooding

“…Both the production and injection wells were constrained by the maximum liquid flow rate of 636.5 m 3 /day. The flooding schedules are described as follows: The water was made up to increase the salinity to close to the optimum value, which was still lower than the three-phase salinity limit [27]. As mentioned previously, the liquid injection rate was constrained to a maximum of 636.5 m 3 /day.…”