Alkaline/Surfactant/Polymer Processes: Wide Range of Conditions for Good Recovery
- Shunhua Liu (Occidental Oil and Gas) | Clarence A. Miller (Rice University) | Robert Feng Li (Rice University) | George Hirasaki (Rice University)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- June 2010
- Document Type
- Journal Paper
- 282 - 293
- 2010. Society of Petroleum Engineers
- 4.3.1 Hydrates, 5.3.2 Multiphase Flow, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.5 Reservoir Simulation, 4.1.5 Processing Equipment, 4.3.3 Aspaltenes, 5.2 Reservoir Fluid Dynamics, 4.1.2 Separation and Treating, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 1.8 Formation Damage, 4.3.4 Scale, 5.4.1 Waterflooding, 5.7.2 Recovery Factors, 5.2.1 Phase Behavior and PVT Measurements
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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.
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