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Results
Gravity-Stable Processes for Dipping or Thick Reservoirs
Doorwar, Shashvat (Chevron Energy Technology Company) | Lee, Vincent (Chevron Energy Technology Company) | Davidson, Andrew (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Abstract Traditionally, all surfactant processes require viscous polymer to mobilize the oil bank. Recent literature shows that for highly dipping reservoirs, a continuous surfactant injection process can be stabilized with gravity alone, by slowing down the processing rate. We extend the gravity stable approach for surfactant slug processes and demonstrate the importance of maintaining gravity stability between slug and chase in addition to gravity stability between microemulsion and slug. Four sandpack experiments were conducted and pictures of the sandpack were taken at regular intervals to provide visual evidence of stable or unstable interfaces. Different color dyes were used to aid visualization of clear fluids. Gravity-stabilized surfactant-only processes eliminate the need of polymer and other facilities associated with surfactant polymer or alkali-surfactant-polymer processes. The slug process described in this paper is a significant improvement on the continuous surfactant injection gravity stable process published earlier.
Three Phase Steady State Flow Experiments to Estimate Microemulsion Viscosity
Davidson, Andrew (Chevron Energy Technology Company) | Nizamidin, Nabijan (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Unomah, Michael (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Abstract Low microemulsion viscosity is critical for the success of chemical EOR. Typical microemulsion viscosities are measured using a rheometer and are considered to be static measurements. Given that microemulsions have a propensity to show non-Newtonian behavior, static viscosity measurements are not scalable to dynamic viscosities observed in cores and hence difficult to scale-up to field designs using simulations. We present a technique to measure dynamic microemulsion viscosity using a modified two-phase steady state relative permeability setup. Such dynamic viscosities provide a more practical feel for microemulsion viscosity under reservoir conditions in the pores and allow for selection of low microemulsion viscosity formulations. A two-phase steady state relative permeability setup was used with continuous co-injection of oil and surfactant. A glass filled sand pack was used as a surrogate core and the injection fluids were allowed to equilibrate into the appropriate phases as determined by the phase behavior. For the rapidly equilibrating and low viscosity Winsor Type III formulations three phases are clearly observed in the sand packs. Using the phase cuts in the sand pack/effluent and the known oil and water viscosities, we can estimate the microemulsion viscosity. Both low and high viscosity formulations were tested in corefloods and oil recovery measured to illustrate the importance of low viscosity microemulsions for oil recovery. As expected, the low viscosity microemulsions correlated with higher oil recovery. In addition, the equilibration times to reach Winsor Type III microemulsions were also linked to better oil recovery. For the well behaved formulations that equilibrated in less than 2 days the static microemulsion viscosity correlated well with the dynamic viscosity. The modified steady state relative permeability setup can accurately estimate microemulsion viscosity and allow for better screening of surfactant formulations identified for field flooding. The dynamic microemulsion viscosities can also provide inputs for numerical simulation and better predict microemulsion behavior in the subsurface during field surfactant floods.