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Evaluation and Prediction of Emulsion Formation in Produced Fluids during an ASP Flood Applied to a Carbonate Reservoir in Kuwait
- Publisher: European Association of Geoscientists & Engineers
- Source: Conference Proceedings, IOR 2019 – 20th European Symposium on Improved Oil Recovery, Apr 2019, Volume 2019, p.1 - 19
Abstract
Summary
This work is concerned with the nature of produced fluids resulting from ASP injection in a carbonate reservoir in Kuwait. The main objective is to examine and identify the nature of produced emulsions at conditions and chemical concentrations that are predicted by numerical simulation studies of the ASP pilot. The laboratory element of the work provides emulsion handling insight before the pilot begins, to reduce potential downtime and production costs.
Laboratory tests and numerical simulations were used to identify the nature of the produced fluids. The simulations used a pilot-scale model to determine realistic ranges of chemical concentrations. The laboratory study used these pre-determined concentration ranges to form, observe, and characterize the emulsions. Key variables that increase emulsion formation and stability are determined. Variables studied include total surfactant concentration, surfactant ratio, polymer, effects of crushed core, temperature, pH, salinity, and viscosity.
O/W and W/O emulsions were formed with a typical emulsion stability pattern of sedimentation followed by coalescence. The emulsion stability varied with conditions. The conditions leading to the most-stable and problematic emulsions included high surfactant, high polymer concentrations, low temperatures, and high salinity. Dense, creamy emulsions were the most stable. When surfactant concentration was increased, interfacial tension decreased, stability increased, and water and oil qualities decreased. A low interfacial tension allowed smaller (more stable) droplets to form, slowed sedimentation, and if low enough stabilized drops against coalescence. As polymer concentration increased, the aqueous viscosity increased and slowed sedimentation, water quality increased, and oil quality decreased. Shearing the polymer (reducing the viscosity) increased sedimentation. Emulsion stability decreased markedly when the temperature was increased. Sedimentation and coalescence were faster, giving an improved oil quality. Lower oil/water viscosities and densities, plus higher thermal energy destabilize the emulsions.
Pilot recommendations: At low surfactant concentration, adequate residence time in the separator is needed, where the phases exiting will be easier to break. For higher surfactant concentrations, in-field bottle-testing of stable, dense emulsions is needed to select a chemical demulsifier and neutralize the surfactant. The success of chemical EOR pilots can be jeopardized due to the formation and stability of produced emulsions. Increased downtime and unplanned mitigation costs may ruin a pilot. Limited ASP emulsion handling resources are available in industry due to the limited ASP pilots made public worldwide. This work provides additional produced emulsion resources and investigations before the pilot begins and also addresses new challenges in a carbonate reservoir ASP flood.
Abstract
This work is concerned with the nature of produced fluids resulting from ASP injection in a carbonate reservoir in Kuwait. The main objective is to examine and identify the nature of produced emulsions at conditions and chemical concentrations that are predicted by numerical simulation studies of the ASP pilot. The laboratory element of the work provides emulsion handling insight before the pilot begins, to reduce potential downtime and production costs.
Laboratory tests and numerical simulations were used to identify the nature of the produced fluids. The simulations used a pilot-scale model to determine realistic ranges of chemical concentrations. The laboratory study used these pre-determined concentration ranges to form, observe, and characterize the emulsions. Key variables that increase emulsion formation and stability are determined. Variables studied include total surfactant concentration, surfactant ratio, polymer, effects of crushed core, temperature, pH, salinity, and viscosity.
O/W and W/O emulsions were formed with a typical emulsion stability pattern of sedimentation followed by coalescence. The emulsion stability varied with conditions. The conditions leading to the most-stable and problematic emulsions included high surfactant, high polymer concentrations, low temperatures, and high salinity. Dense, creamy emulsions were the most stable. When surfactant concentration was increased, interfacial tension decreased, stability increased, and water and oil qualities decreased. A low interfacial tension allowed smaller (more stable) droplets to form, slowed sedimentation, and if low enough stabilized drops against coalescence. As polymer concentration increased, the aqueous viscosity increased and slowed sedimentation, water quality increased, and oil quality decreased. Shearing the polymer (reducing the viscosity) increased sedimentation. Emulsion stability decreased markedly when the temperature was increased. Sedimentation and coalescence were faster, giving an improved oil quality. Lower oil/water viscosities and densities, plus higher thermal energy destabilize the emulsions.
Pilot recommendations: At low surfactant concentration, adequate residence time in the separator is needed, where the phases exiting will be easier to break. For higher surfactant concentrations, in-field bottle-testing of stable, dense emulsions is needed to select a chemical demulsifier and neutralize the surfactant. The success of chemical EOR pilots can be jeopardized due to the formation and stability of produced emulsions. Increased downtime and unplanned mitigation costs may ruin a pilot. Limited ASP emulsion handling resources are available in industry due to the limited ASP pilots made public worldwide. This work provides additional produced emulsion resources and investigations before the pilot begins and also addresses new challenges in a carbonate reservoir ASP flood.
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