Increased Oil Tolerance of Polymer-Enhanced Foams: Deep Chemistry or Just "Simple" Displacement Effects?

Abstract

In recent years, foam treatment has moved towards field qualification as a practical method for gas shut-off in oil wells producing at excessive gas/oil ratio (GOR). However, the time of gas blockage achieved in most field trials is limited to a few months. This may be too short for general industry acceptance of this economically very attractive niche technology. Laboratory and scattered field data show that addition of polymers can enhance foam performance in oil-reservoir rock. However, little is known on precisely how addition of polymer improves the application-critical properties of a foam system. This paper reports new experimental data for gas-blocking foams that appear to have superior oil tolerance caused by the presence of polymer. The results are discussed in a context of field experience with gas shutoff foams and thin-film research. Core tests were conducted at reservoir temperatures, with crude oils from fields where field trials were done or planned. Systems studied include AOS surfactants and polyacrylamide polymers, bulk chemicals used in the field. Foam performance was measured in gas-blockage mode and forced flow. At zero oil saturation in cores, good foam performance was obtained with or without polymer added and with no systematic trends. Film properties for the same systems similarly gave no clear correlation with polymer concentration. A new high-pressure cell built to allow direct visual observation of oil/foam interaction at reservoir conditions was used to see if polymer influenced the oil tolerance of AOS-based foams. No effect on the spreading/entering regime was found. With oil in the core, AOS foams gave positive results only if containing polymer. Foam performance correlated with the level of oil saturation. It was hypothesised that the apparent oil tolerance of AOS/polymer foam was caused by the lower oil saturation in the core during foam generation. This hypothesis was tested by pre-flushing a core with the polymer/surfactant solution, but then generating gas-blocking foam from a polymer-free foamer solution. The resulting performance was identical to that of the polymer-enhanced foam. Hence, no chemical interactions of polymer and surfactant, or any liquid-film stabilisation mechanism, is required to explain these results. The role of polymer in the systems studied was only to improve the foamer/oil displacement by causing more efficient displacement of oil before or during foam generation. If generally valid, these results have two major consequences:Product selection by optimising polymer-foam systems for oil tolerance at a given oil saturation level is bound to fail.Foam process design should emphasise the need to create and maintain low oil saturations in the treated zone. Introduction The use of foam for controlling the flow of steam in an oil reservoir is today a field-proven technology. Outside of thermal operations, field trials in recent years also show that foams can be used for gas shut-off in high-GOR oil producers. Field tests show that foam can be effective in controlling gas coning [1], injector-to-producer breakthrough of gas in high-permeability zones [2] and, at least in some situations, gas cusping [3, 4]. However, the duration of gas shut-off in successful field trials has so far been limited to periods of typically two to six months. While periodic re-treatment every few months may be quite acceptable in some oil fields, e.g. simple on-shore wells, foam treatment would be more widely applicable if the effects of foam on gas flow could be extended to match those of polymer gels for water shut-off, which can be effective for years. In a previous paper [5], we showed that the duration of gas blockage in oil-saturated sandstone cores at generic reservoir conditions could be extended significantly by adding suitable polymers to the foaming-agent solutions. However, that study also indicated that too high concentration of polymer could be detrimental to foam performance. It also failed to show further advantage of gelling or cross-linking the polymer, which was claimed by some investigators to yield additional benefits [6].

Experimental Study of the Stabilization of CO2 Foam by Sodium Dodecyl Sulfate and Hydrophobic Nanoparticles

“…CO 2 flooding is an important technology for enhanced oil recovery (EOR) in tertiary oil recovery. − In response to increasing requirements for reducing CO 2 emissions, CO 2 flooding has been widely used in the exploitation of crude oil. Because of the low viscosity and low density of CO 2 , gas channeling and gravity segregation usually occur under reservoir conditions, resulting in a low sweep efficiency. , To solve this problem, CO 2 foam produced by a surfactant solution is widely used to control the CO 2 mobility. − However, CO 2 foam stabilized solely by surfactant has some undesirable properties. For example, CO 2 foam is unstable when in contact with crude oil, and the surfactant easily decomposes under the high temperatures and high salt contents of oil reservoirs.…”

“…Because of the low viscosity and low density of CO 2 , gas channeling and gravity segregation usually occur under reservoir conditions, resulting in a low sweep efficiency. 4,5 To solve this problem, CO 2 foam produced by a surfactant solution is widely used to control the CO 2 mobility. 6−8 However, CO 2 foam stabilized solely by surfactant has some undesirable properties.…”

“…16 Meanwhile, surface-modified nanoparticles have affinity both for CO 2 and water, improving the binding force of CO 2 and water. 17 (4) The solubility of CO 2 in water is very high (for example, the solubility of CO 2 in beverages is 50 times higher than that of N 2 ), which increases gas diffusion between bubble films and causes poor stability. 4 Nanoparticles adsorbed on the interface CO 2 and water can reduce the contact area between the gas bubble and liquid film, thereby reducing gas diffusion.…”

“…17 (4) The solubility of CO 2 in water is very high (for example, the solubility of CO 2 in beverages is 50 times higher than that of N 2 ), which increases gas diffusion between bubble films and causes poor stability. 4 Nanoparticles adsorbed on the interface CO 2 and water can reduce the contact area between the gas bubble and liquid film, thereby reducing gas diffusion. The properties mentioned above illustrate that nanoparticles are highly suitable for stabilizing CO 2 foam under reservoir conditions.…”

Evaluation of the Performances of Foam System as an Agent of Enhancing Oil Recovery

“…Therefore, the foam half-life time is shortest for light oil, and longest for heavy oil. A polymer can enhance the stability of foam [28]. The foaming volume, draining halflife time, and foam half-life time for different concentrations of polymer are shown in Figure 9.…”