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.
© 2010. Society of Petroleum Engineers
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History
- Original manuscript received:
20 February 2008
- Meeting paper published:
20 April 2008
- Revised manuscript received:
23 March 2009
- Manuscript approved:
8 September 2009
- Published online:
3 March 2010
- Version of record:
17 June 2010
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