Two major applications of injecting dense carbon dioxide (CO2) into the petroleum reservoirs are enhanced oil recovery and sequester CO2 underground. For enhanced oil recovery applications, CO2 has low miscibility pressure causing the swelling of crude oil and reducing its viscosity therefore improving the macroscopic sweep process. However, the low viscosity of injected CO2 compared with the reservoir fluids causes the fingering of CO2, which may lead to bypassing huge amount of oil, early breakthrough of CO2, and increasing the gas to oil ratio (GOR). The use of direct thickeners, such as polymers, is one of the techniques used to increase the CO2 viscosity. Nevertheless, the solubility of polymers in CO2 and the high cost of soluble polymers are the main challenges facing this technique. In this study, a novel, soluble, and cost-effective thickener is proposed to directly increase the CO2 viscosity. In this study, a PVT high pressure and high temperature (HPHT) apparatus was used to evaluate the compatibility and the solubility of the thickener in dense CO2. Also, a custom designed apparatus was used to measure the viscosity of dense CO2 in the presence of the thickener at different conditions. The assessment was conducted at different experimental pressures, temperatures, and thickener concentrations. The effect of pressure on the solubility of the thickener in CO2 and on the measured viscosity of CO2 was evaluated at 1500, 2000, 2500, and 3000 psi. Also, the influence of temperature was evaluated at 25 and 50°C. Moreover, the concentrations used to study the effect of thickener concentration on the measured viscosity of CO2 ranged between 0.10-2 %. The results from laboratory experiments clearly demonstrated that the addition of the thickener at certain conditions can significantly impact the dense CO2 viscosity. The results revealed that there must be a minimum pressure at which the thickener dissolves in the dense CO2. The solubility of the thickener can occur when the CO2 is either in the liquid or supercritical phase. The results also pointed out that the CO2 viscosity increased as the pressure increased. The increase of CO2 pressure can significantly impact the solubility of the thickener in the dense CO2 and consequently the CO2 viscosity. The increase of the thickener concentration also had a significant impact on the measured CO2 viscosity. The results showed that the CO2 viscosity increased with the thickener concentration. The CO2 viscosity increased 100 to 1200 -fold as a result of adding the thickener depending on the experimental conditions
Enhanced oil recovery by CO2 injection is an effective method for recovering additional oil beyond waterflooding. In recent years it has garnered a lot of attention for two primary reasons: (a) the stable high price of oil and (b) environmental aspects of CO2 sequestration. Its use has been increasing steadily over the past few years. In many respects it is a win-win situation with CO2 sequestration and additional, incremental oil produced. However, the CO2-EOR process is handicapped, especially in thick reservoirs, by CO2 gravity override. Due to density differences between the injected CO2 and resident fluids in the reservoir, the lighter CO2 tends to rise to the top of the reservoir thereby bypassing some of the remaining oil. This results in poor sweep efficiency and conformance. Different techniques have been used to overcome the CO2 gravity override by either increasing its density, viscosity, or reducing its relative permeability. This paper investigates the use of gelling CO2-water emulsions, stabilized by silica nano-particles, to control the mobility of CO2. The stability of nano-particles was first investigated using iso-octane (iC8) as a proxy for CO2. The stability of these emulsions, or foams, was investigated as a function of nano-particles concentration, type, hydrophilicity degree, and also as a function of iC8/water ratio. The silica nano-particles concentration ranged from 0.5 to 2 wt%, and iC8 phase volume ranged between 50 and 90%. Stability experiments were conducted at room temperature and up to 17 hours using both hydrophobic and hydrophilic colloidal silica nano-particles. Following the screening studies with iC8, rheological measurements were made using CO2 at 200°F and 1,800 psi at different (CO2/water) ratios and nano-particles concentrations. Compared to pure liquid CO2, high emulsion viscosities from 1.1 to nearly 2.5 cP were achieved. These values represent almost a 100-fold increase over pure sc-CO2 viscosity. Additionally, in some cases rigid gels were observed with time following emulsion generation. The CO2-water-nanoparticle emulsions were generally stable. This work provides the rheological results of the emulsion systems as a function of time, nano-particles concentration and CO2 phase volume. The high viscosity CO2/water emulsions have the capability to enhance CO2 mobility, act as a diverting agent during CO2-EOR, and improve sweep efficiency.
Carbon dioxide miscible flooding is a proven EOR method. It faces two significant challenges: gravity override and early CO2 break through. Many researchers have investigated different methods to control CO2 mobility and improve its sweep efficiency. This paper, for the first time, investigates the use of a new and unique CO2-foam (emulsion) to control CO2 mobility and also as a conformance control technique in heterogeneous reservoirs with high permeability contrast within carbonate rocks. The new CO2-emulsion system consists of 50-70 vol% supercritical CO2, 50-30 vol% of water-based polysaccharide linear polymer and a foaming agent (surfactant). Several experiments were conducted using HPHT visual cell to assess the CO2-emulsion stability as a function of temperature, pressure and time. In addition, the rheological properties of the CO2-emulsions were investigated at different shear rates, different pressures and mixing ratios, and at an operating temperature of 220°F. Special dual core flooding experiments were conducted using live oil at reservoir conditions to investigate the effectiveness of CO2-emulsion system in enhancing oil recovery. Several experiments were conducted to explore the effect of injection rate, injection mode and slug volume on incremental oil recovery. These experiments were performed using dual core holders with different permeable carbonate composite stacks, and permeability contrasts up to 35. Results based on this study have shown that the CO2-emulsion system is stable at 210°F for extended periods of time without any emulsion breakage or phase separation. The effective viscosity of CO2 was increased by 3-4 orders of magnitude and approached 100 cP at reservoir conditions. Results also show the emulsion's ability to severely reduce permeability of the higher permeable cores resulting in significant incremental oil recovery from the lower permeable cores. This new and unique emulsion system has the ability to be created in-situ to provide better mobility control of the injected CO2. Additionally, this paper provides optimal design parameters of the new emulsion system to behave as a conformance control agent, and also to enhance the recovery of oil following water and CO2 floods.
Injecting carbon dioxide (CO2) into oil reservoirs has the potential to enhance oil recovery (EOR) and sequester CO2 underground. While CO2 injection has been successful, a major challenge facing this technique is enhancing volumetric sweep efficiency. Some of the factors that contribute to this challenge are the low density and viscosity of injected gas relative to reservoir fluids. The use of foam is one of the most promising techniques to increase the CO2 apparent viscosity, thereby improving volumetric sweep efficiency. Increasing the CO2 viscosity by using surfactants has the potential to mitigate some of the challenges associated with CO2 injection projects. The objective of this work is to investigate the effect of various surfactants on CO2-foam viscosity. Four surfactants were used to evaluate the foam generation and rheological properties of CO2-foams at high pressure and temperature. Dynamic foam viscosity measurements were conducted in a special foam rheology apparatus with supercritical (sc-CO2) under high pressure (3200 psi), temperature (210°F) and salinity conditions. The foam was generated by injecting sc-CO2 and surfactant at different concentrations (0.20, 0.50 and 1.00 wt %), shear rates (10-600 s-1) and qualities (70, 85 and 90%). The results indicate that all surfactants were able to generate good quality foam at high pressure and temperature. The foam viscosity increases with surfactant concentration. All foams exhibited shear thinning behavior, with foam viscosity decreasing with increasing shear rates. In general, the highest viscosity for each surfactant was reported at the lowest shear rates. The results also showed that the foam quality has an impact on foam viscosity for some cases. The highest foam viscosities for surfactant 2 were achieved at 85% quality. However, the quality had no significant impact on foam viscosity for surfactant 3.
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