Low Adsorbing CO2 Soluble Surfactants for Commercially Viable Implementation of CO2 Foam EOR Technology

Several gas Enhanced Oil Recovery (EOR) pilots enhanced with aqueous-foam based conformance solutions have been implemented in the last 30 years. While these pilots were technically successful, there were economic challenges limiting their commercial viability. Many of these pilots were implemented with water-soluble foaming surfactants that can get adversely affected by near wellbore gas-water gravity segregation and adsorption loss up to 90% of the injected surfactant. Novel, gas-soluble surfactants can be injected with the gas phase where these surfactants are carried with the gas to thief zones faster and deeper with relatively lower adsorption to the rock surface. However, the conventional foam modeling approach relied only on the surfactant concentration in brine to determine foam strength, which adversely predicted the performance of gas soluble surfactants. With proven laboratory evaluations and multiple successful field implementations, the advantages of low adsorbing and gas soluble surfactants cannot be ignored. In this paper, the advantages of surfactant partitioning to the gas phase are confirmed by correcting the conventional foam modeling approach while simulating 1D transport of CO2-foam displacing brine in porous media. An empirical foam model was developed from the lab scale core flooding work of CO2foam transport through porous media using a novel gas-soluble foaming surfactant. While investigating the performance of gas soluble surfactants, global surfactant concentration was used to determine foam strength as the surfactant can transport to the gas-water interface from both the phases. Lab experiments and simulations with an improved foam modeling approach confirmed that a higher gas phase partitioning surfactant generated robust foam and deeper foam propagation while injecting surfactant with CO2in a water saturated core. In addition, comparing three partition coefficient scenarios around 1 on mass basis, the higher gas phase partitioning surfactant showed the larger delay in gas breakthrough. Overall, the simulation results with our better modeling approach do support the advantages of the higher gas phase surfactant partitioning in deeper foam transport and conformance enhancement for the gas-EOR technology.

Unlock the Potentials to Further Improve CO2 Storage and Utilization with Supercritical CO2 Emulsions When Applying CO2-Philic Surfactants

Supercritical CO2 (ScCO2) emulsion has attracted lots of attention, which could benefit both climate control via CO2 storage and industry revenue through significantly increased oil recovery simultaneously. Historically, aqueous soluble surfactants have been widely used as stabilizers, though they suffer from slow propagation, relatively high surfactant adsorption and well injectivity issues. In contrast, the CO2-soluble surfactants could improve the emulsion performance remarkably, due to their CO2-philicity. Here, comprehensive comparison studies are carried out from laboratory experiments to field scale simulations between a commercially available aqueous soluble surfactant (CD 1045) and a proprietary nonionic CO2-philic surfactant whose solubility in ScCO2 and partition coefficient between ScCO2/Brine have been determined. Surfactant affinity to employed oil is indicated by a phase behavior test. Static adsorptions on Silurian dolomite outcrop are conducted to gain the insights of its electro-kinetic properties. Coreflooding experiments are carried out with both consolidated 1 ft Berea sandstone and Silurian dolomite to compare the performances as a result of surfactant natures under two-phase conditions, while harsher conditions are examined on fractured carbonate with presence of an oleic phase. Moreover, the superiorities of ScCO2 foam with CO2-philic surfactant due to dual phase partition capacity are illustrated with field scale simulations. ScCO2 and WAG injections behaviors are used as baselines, while the performances of two types of CO2 emulsions are compared with SAG injection, characterized by phase saturations, CO2 storage, oil production, CO2 utilization ratio and pressure distribution. A novel injection strategy, named CO2 continuous injection with dissolved surfactant (CIDS), which is unique for a CO2-philic surfactant, is also studied. It is found that the CO2-soluble surfactant displays much lower oil affinity and adsorption on carbonate than CD 1045. Furthermore, in a laboratory scale, a much higher foam propagation rate is observed with the novel surfactant, which is mainly ascribed to its CO2 affinity, assisted by the high mobility of the CO2 phase. Field scale simulations clearly demonstrate the potentials of CO2 emulsion on CO2 storage and oil recovery over conventional tertiary productions. Relative to traditional aqueous soluble surfactant emulsion, the novel surfactant emulsion contributes to higher injectivity, CO2 storage capability, oil recovery and energy utilization efficiency. The CIDS could further reduce water injection cost and energy consumption. The findings here reveal the potentials of further improving CO2 storage and utilization when applying ScCO2-philic surfactant emulsion, to compromise both environmental and economic concerns.