The goal of this project is to develop mobility control agents using surfactants injected with carbon dioxide (CO2) rather than with water for CO2 enhanced oil recovery (CO2-EOR) in heterogeneous carbonate and sandstone reservoirs. Objectives are to (1) reduce CO2 mobility in CO2 swept portions of the reservoir—but not at the light-hydrocarbon enriched CO2 displacement front; (2) reduce mobility more in higher permeability than in lower permeability intervals; (3) improve distribution of injected fluids in natural fracture networks; (4) reduce the amount of surfactant required to achieve successful mobility control; and (5) achieve displacement efficiency well below the MMP by using surfactants with ultra-low water/oil interfacial tension. These attributes will divert CO2 from swept regions to regions with unswept oil.
The University of Texas at Austin, Austin (UT), TX 78712-1500
Rice University, Houston, TX
CO2 flooding has become a routine technology for EOR worldwide. In the United States, the number of CO2-EOR projects increased from 20 in 1980 to 86 in 2008. Over 600 million tons of CO2 (11 trillion standard cubic feet) transported through 3,500 miles of high-pressure CO2 pipeline was injected into over 13,000 CO2-EOR wells. The oil production rate from CO2 projects in 2010 was 273,000 barrels of oil per day.
CO2-EOR has exhibited strong growth in the past 30 years and has expanded despite fluctuations in oil price. However, there are several issues challenging the oil recovery, economic efficiency, and applicability of the process. The oil recovery efficiency is low, and the CO2 utilization rate—the amount of CO2 injected to recover an incremental barrel of oil—is high. This is due to the low viscosity of CO2 compared to oil and water and the resulting unfavorable mobility ratio. This, combined with reservoir heterogeneities, leads to poor sweep efficiency and bypass of un-contacted oil. This problem is evident by cycling of CO2 through swept intervals. Also, many shallow reservoirs are below the minimum miscibility pressure (MMP) for efficient CO2 displacement, and this oil is typically not targeted for CO2 flooding.
The inability to accommodate these needs across reservoirs has previously limited CO2 foam application. The proposed approach differs from previous practice primarily because (a) the process design is based on phase behavior and foam morphology/stability associated with colloid and interfacial science and thermodynamics; (b) the surfactant (in the case of nonionic surfactants) is injected with CO2 rather than in water; (c) CO2 foam with surfactant that generates low interfacial tension between oil and water can have good displacement efficiency at pressures well below the MMP; and (d) these processes can be used in the paleo-residual oil zone as well as in the waterflooded residual oil zone. Injecting surfactant with CO2 will place more of the surfactant in the thief zone compared to injecting surfactant with water.
The method to be developed in this project will improve the mobility ratio of CO2 flooding and increase recovery efficiency, which in turn will reduce the cost of purchased and recycled CO2 and broaden the application of CO2 flooding to more heterogeneous reservoirs. Combining surfactant flooding and CO2 foam mobility control will make shallow reservoirs with pressures below the MMP candidates for a combined CO2/surfactant EOR process. A revised national resource assessment for CO2-EOR (July 2011), prepared for DOE by Advanced Resources International, indicated that “Next Generation” CO2-EOR can provide 137 billion barrels of additional technically recoverable domestic oil, with about half (67 billion barrels) economically recoverable at an oil price of $85 per barrel. The proposed work will contribute to such advanced technology.
Improving the efficiency of CO2-EOR not only increases the supply of domestic oil but, by making the process more broadly applicable, also increases the demand for CO2 in more geographic locations, and thus promotes its sequestration.
Cationic, nonionic and zwitterionic surfactants have been explored to identify candidates that have the potential to satisfy all the key requirements for CO2 foams in EOR over broad reservoir conditions (i.e. temperature, pressure, salinity, water hardness). We have examined the formation, texture, rheology and stability of CO2 foams as a function of the surfactant structure and formulation variables, including temperature, pressure, water/CO2 ratio, surfactant concentration, salinity and concentration of oil. Furthermore, the partitioning of surfactants between oil and water, as well as CO2 and water, was examined in conjunction with adsorption measurements on both sandstone and limestone to develop strategies to optimize the transport of surfactants in reservoirs.
The novel switchable amine surfactants satisfied simultaneously the requirements of high CO2 solubility and formation of CO2 foams in the presence of water. Moreover, these switchable surfactants showed low partitioning towards oil and favorable CO2/brine partitioning. The former property is important in minimzing surfactant retardation due to partitioning into oil. In addition to cationic surfactants, nonionic linear and branched ethoxylate surfactants with high optimum ethylene oxide (EO) number formed strong foams in sand/bead packs and remained highly viscous in a capillary tube as bulk foam. Both switchable surfactants and nonionic surfactants could stabilize strong foam at very low surfactant concentration (close to 0.05 wt%) and very high salinity (9 wt% NaCl for a nonionic surfactant and up to 18 wt% NaCl, and with high calcium ion levels, for a cationic switchable surfactant). The surfactant efficiency for lowering the interfacial tension between brine and CO2 as a function of CO2 density up to 18 mN/m was achieved. Both switchable surfactants and nonionic surfactants also formed unstable oil-water/brine emulsion at elevated temperatures. It has been demonstrated that CO2 foams broke in the presence of mobile oil as a function of the oil concentration. Thus, these smart surfactants may be used to generate foam that can stabilize the displacement front in CO2 flooding.
The presence of silica and/or clay may significantly affect the adsorption of cationic surfactants on carbonates. To verify this hypothesis, the surface chemistry of four kinds of natural carbonates, including dolomite and limestone samples, was analyzed. X-ray photoelectron spectroscopy (XPS) revealed that a substantial amount of silicon and aluminum exist in natural carbonates but not in synthetic calcite. Energy-dispersive X-ray spectroscopy (EDX) shows that silicon is widely distributed on dolomite surface. Static adsorption experiments on various carbonates were perfrormed on cationic and anionic surfactants. The results show that the adsorption plateau was highly dependent on the atomic ratio of (Si+Al)/(Ca+Mg) of the carbonate samples. This finding indicates that, in addition to nonionic surfactants, cationic surfactants may be good candidates for CO2 foam EOR with low adsorption on carbonates if the silica and clay contents in the carbonate formation are low.
Micromodels made with polydimethylsiloxane have been constructed for observing foam in heterogeneous pore systems. High-speed microscopy videos highlight tunable bubble generation via a flow-focusing microchannel geometry, bubble stability at the foam-oil interface, and dynamic foam behavior at the pore scale (including both fractures and model porous media). Foam sweep and oil displacement was studied as a function of foam quality, bubble size, surfactant type, and fracture-matrix permeability. Comparisons were made with pure gas and surfactant-free flooding, showing improved sweep and oil mobilization (up to 98% oil-in-place displaced) for foam systems.
High pressure core floods were successfully conducted to evaluate the capacity of foam to divert CO2 from high permeability zone (thief zone) into low permeability zone (upswept oil-rich zone). The permeability contrast (defined as the ratio of high permeability to low permeability) for the core floods was chosen based on typical reservoir permeability variations from both sandstone and carbonate fields. One of the important findings was that at very low fluid rates (i.e., far field rate conditions), the mobility of CO2 in foam is quite uniform in both high and low permeability rocks. This indicates that foam is stronger in higher permeability zone to resist preferential flow of CO2 in this zone, resulting in higher sweep efficiency. For high flow rates (i.e., near wellbore rate conditions), the effective permeability of CO2 increases with injection rates. Therefore, strong foam that reduces injectivity does not develop near the wellbore region. The core flood results are also useful for understanding of local foam rheological behaviors and empirical approach based foam modeling. CO2 soluble surfactants could reduce the delay of foam propagation, enhancing foam robustness. The level of foam robustness enhancement varies with surfactant partition coefficient. As the partition coefficient of the foaming surfactant increases from zero (anionic surfactant) to above 1.5 at the core flood conditions, the rate of strong foam propagation appears to be highest at around 0.1. The dependency of foam robustness on surfactant partition coefficient can be explained based on the effect of critical surfactant concentration on foam stability and the spreading of surfactant concentration distribution due to partitioning.
A 3D pore-network model of computer-generated sandstone coupled with fluid models that represent a lamella flow through a pore throat has been successfully used to quantify two key rheological features of foam mobility (i.e., gas relative permeability and effective gas viscosity) and their influencing factors. It was found that flowing gas fraction increases as the overall lamella density in the pore network decreases at a constant pressure gradient. This results in significant variation of threshold pressure gradients at high overall lamella density. Relative gas permeability is a strong non-linear function of flowing gas fraction. This observation disagrees with most of the existing theoretical models for the effect of gas trapping on relative gas permeability in which a linear relationship is commonly assumed. Moreover, the shape of the relative gas permeability curve is poorly sensitive to overall lamella density. The findings on the dynamics of foam trapping and remobilization indicate that both flowing and trapped lamella densities vary with pressure gradient, but are not necessarily the same. This preliminary result provides insight into the least explored aspect of population balance based modeling approaches, that is the kinetics of gas trapping. It is also relevant to understanding phase trapping during multi-phase flow. Empirical and mechanistic pore-scale apparent gas viscosity models are evaluated and compared. It is found that all the models give almost the same functional relationship between flowing gas fraction and pressure gradient. This would facilitate scaling of flow rate with pressure gradient and testing a range of shear-thinning and yield-stress behavior in a simple format. Effective gas viscosity is a strong function of flowing lamella density. The nonlinearity of this function is opposed to the existing foam viscosity models developed for foam flow in porous media and reported here for the first time. In addition, shear thinning foam flow is more obvious at high flowing lamella density, while Newtonian flow becomes significant at relatively low flowing lamella density. Scaling of effective gas viscosity with flowing lamella density depends on how the later quantity is defined. Effective gas viscosity is a unique function of the number of flowing lamellas normalized to the total number of pore throats open to flow. However, it also scales with overall lamella density if the number of flowing lamellas is normalized to the flowing gas volume. This issue has not been addressed in the literature of modeling of foam in porous media because the dynamics of gas trapping and remobilization and its effect on foam mobility has been neglected.
Scaling of foam process to field has been conducted. Different injection strategies have been investigated, including conventional CO2 insoluble surfactants and the influences of surfactant partitioning between CO2 and water phases on field-scale foam performance. One of the significant findings was that higher surfactant partition coefficient results in lower gas production rate over a relatively short period of time, owing to deeper surfactant and foam propagation into the reservoir. However, this early-time production behavior dramatically changes at later time. An increase in surfactant partition coefficient leads to more spreading of surfactant concentration distribution towards the producer, enhancing the significance of surfactant concentration effect. Therefore, surfactants with relatively lower partition coefficients can improve better vertical sweep efficiency. This particular effect of surfactant partitioning improves not only sweep efficiency, but also well injectivity. The average well bottomhole pressure decreases with increasing surfactant partition coefficient regardless of cycle size. Increasing slug size improves vertical sweep efficiency only for CO2 insoluble surfactant at the expense of well injectivity. Furthermore, for CO2 insoluble surfactant, an increase in slug size significantly improves vertical sweep efficiency. However, foam is actually weaker as the water-CO2 cycle increases for all the CO2 soluble surfactants. Surfactant concentration gradient is dependent on the cycle size and the magnitude of partition coefficient. If the latter is fixed, an increase of water-CO2 cycle reduces surfactant concentration gradient that may impair the continuation of strong foam propagation.
Recently, the project team has collaborated with Tabula Rasa to identify a dolomite reservoir candidate for foam application. East Seminole has been recommended based on its heterogeneity, formation fluid properties, historical reservoir performance, and operational constraints. Tabula Rasa has planned to start water-alternating-gas injection for these patterns in early 2016 for about 9 months to establish the injection and production base lines for a foam trial. A foam pilot design will be developed based on the injection/production base lines and the results of all lab tests from this project.
The project has been completed and the final report is available below under "Additional Information".
NETL – Eric Smistad (Eric.Smistad@netl.doe.gov or 281-494-2619)
University of Texas at Austin – Quoc Nguyen (firstname.lastname@example.org or 512-471-1204)
Final Project Report [PDF-11.9MB]