Prediction and experimental measurements of Water-in-Oil emulsion viscosities during alkaline surfactant injections
- Amrit Kalra (Shell International E&P Inc) | Ashwin Venkatraman (U. of Texas at Austin) | Kirk H. Raney (Shell Exploration & Production) | Birol Dindoruk (Shell Intl E&P Co)
- Document ID
- Society of Petroleum Engineers
- SPE Enhanced Oil Recovery Conference, 19-21 July, Kuala Lumpur, Malaysia
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 2.5.2 Fracturing Materials (Fluids, Proppant), 5.4.1 Waterflooding, 4.3 Flow Assurance, 5.7.2 Recovery Factors, 5.3.2 Multiphase Flow, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 4.2 Pipelines, Flowlines and Risers, 5.2 Reservoir Fluid Dynamics
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Oil production is generally a complicated multi-phase flow inside pipelines, with possible W/O emulsions present with other usual phases such as free water and free oil. The water-in-oil (W/O) emulsions formed can present significant hurdles in production facilities for pumping fluids and during pipeline transport. It is well known that high shear rates provided by pumps, chokes or valves result in stable emulsion behavior for a field in primary production. Several field tests are underway to test the potential of surfactant flooding as a tertiary recovery mechanism. The effect of addition of surfactants on the
emulsion rheology of production fluids, as in Alkaline Surfactant Polymer (ASP) flooding, is not very well understood. This understanding of W/O emulsion rheology in ASP injected oil recovery is essential for design of pumps and pipelines as well as for handling flow assurance issues.
In this paper, we report results from experiments as well as modeling of W/O emulsion rheology that can form during ASP injections. We focus here only on the Alkaline Surfactant (AS) part of these injections in order to clearly understand the impact of surfactants and removing the uncertainities that come with large rheology changes with polymer addition. The effect of surfactants on the rheology of W/O emulsions was studied by making two different types of emulsions: 1) native brine W/O emulsions without surfactants to provide a baseline 2) W/O emulsions with surfactants used in AS injections. This way, the impact of AS injections on emulsion rheology can easily be quantified. A new correlation is developed, based on inhouse historical experimental data, to describe rheology of emulsions without surfactants. This correlation should assist in managing the uncertainties that come from extrapolating emulsion rheology measured in the laboratory to actual field conditions. Further, in order to understand the effect of AS injections, new experimental measurements were made by adding surfactants to brine solutions. The addition of surfactants resulted in different rheology as compared to emulsions formed by brine solutions. These differences have been attributed to the water-oil interfacial tension (IFT), and IFT was added to modify the original correlation. To our knowledge, this is the first study that explicitly relates emulsion rheology with interfacial tension.
Some of the predictions regarding oil production using primary depletion and secondary water floods points to a significantly large fraction of original oil in place. The capillary trapping of oil in the pores and inefficient sweep during secondary water flooding are factors primarily responsible for poor oil recoveries. Enhanced oil recovery techniques using chemicals reduce capillary trapping and increase oil recovered from reservoirs. Among the chemicals injected, the ASP (Alkali-Surfactant-Polymer) injection technique that includes a mix of an alkali, surfactant and polymer addresses both volumetric sweep efficiency (polymer part) and capillary trapping (surfactant part).
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