Impact of Surfactant Structure and Oil Saturation on the Behavior of Dense CO2 Foams in Porous Media

Chabert, Max; Nabzar, L.; Beunat, Virginie; Lacombe, Emie; Cuenca, Amandine

doi:10.2118/169116-ms

Cited by 10 publications

(18 citation statements)

References 10 publications

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“…The foam film permeability, which is a measure of foam stability, increases with increasing temperature [11]. Foam behavior within a porous medium at reservoir conditions can significantly vary from the bulk experiments, particularly under different thermodynamic conditions [12].…”

Section: Introductionmentioning

confidence: 99%

Effect of temperature on foam flow in porous media

Kapetas

Vincent-Bonnieu

Danelis

et al. 2016

Journal of Industrial and Engineering Chemistry

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Foam can increase sweep efficiency within a porous medium, which is useful for oil-recovery processes [1]. The flow of foam in porous media is a complex process that depends on properties like permeability, porosity and surface chemistry, but also temperature. Although the surface activity of surfactants as a function of temperature is well described at the liquid/liquid or liquid/ gas interface, data on the effect of temperature on foam stability is limited, especially in porous media.In this work, we tested a surfactant (AOS) at different temperatures, from 20°C to 80°C, in a sandstone porous medium with co-injection of foam. The pressure gradient, or equivalently the apparent viscosity, was measured in steady-state experiments. The core-flood experiments showed that the apparent viscosity of the foam decreased by 50% when the temperature increased to 80°C. This effect correlates with the lower surface tension at higher temperatures. These results are compared to bulk foam experiments, which show that at elevated temperatures foam decays and coalesces faster. This effect, however, can be attributed to the faster drainage at high temperature, as a response to the reduction in liquid viscosity, and greater film permeability leading to faster coarsening. Our results using the STARS foam model show that one cannot fit foam-model parameters to data at one temperature and apply the model at other temperatures, even if one accounts for the change in fluid properties (surface tension and liquid viscosity) with temperature. Experiments show an increase in gas mobility in the low-quality foam regime with increasing temperature that is inversely proportional to the decrease in gas-water surface tension. In the high-quality regime, results suggest that the water saturation at which foam collapses fmdry increases and P c * decreases with increasing temperature.

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Section: Introductionmentioning

confidence: 99%

Effect of temperature on foam flow in porous media

Kapetas

Vincent-Bonnieu

Danelis

et al. 2016

Journal of Industrial and Engineering Chemistry

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“…A summary of many studies on CO 2 -foam in sandstone and in carbonate rock material in the absence of oil reveals that few surfactants can generate a CO 2 -foam of similar strength and stability under elevated experimental conditions as those reported with the N 2 -and CH 4foams. However, all of the studies on CO 2 -foam referenced below show that the CO 2 mobility can be lowered with a variety of surfactants, although significant differences in the degree of mobility control have been reported (Alkan et al 1991;Bian et al 2012;Chabert et al 2012Chabert et al , 2014Chen et al 2012;Elhag et al 2014;Heller 1984Heller , 1994Khalil and Asghari 2006;Kuehne et al 1992;McLendon et al 2012;Prieditis and Paulett 1992;Sanders et al 2010;Tsau and Heller 1992;Tsau and Grigg 1997;Yang and Reed 1989;Xing et al 2010;Zeng et al 2016).…”

Section: Co 2 -Foamsmentioning

confidence: 99%

Foam Generation, Propagation and Stability in Porous Medium

et al. 2019

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There have been several foam field applications in recent years. Foam treatments targeting gas mobility control in injectors as well as gas blocking in production wells have been performed without causing operational problems. The most widely used injection strategy of foam has been injecting alternating slugs of surfactant in brine with gas injection. This procedure seems to be beneficial as injection is easy to perform and control below fracturing pressure. Simultaneous injection of surfactant solution and gas may give difficulties, especially with interpretation of the tests, if fracturing pressure are exceeded during the injection period. This paper reviews critical aspects of foam for reservoir applications and intends to motivate for further field trials. Key parameters for qualification of foam are: foam generation, propagation in porous medium, foam strength and stability of foam. Stability is discussed, especially in the presence of oil at reservoir conditions. Data on each of these topics are included, as well as extracted summary of relevant literature. Experimental studies have shown that foam is generated at low surfactant concentration even below the CMC (critical micelle concentration). Results indicate that in situ foam generation in porous medium may depend on available nucleation sites. In situ generation of foam is complex and has been found to be especially difficult in oil wet carbonate rocks. Foam propagation in porous medium has been summarized, and propagation rate for a given experiment seems to be constant with time and distance. Laboratory studies confirm a propagation rate of 1-3 m/day. Field tests performed have not given reliable information of foam propagation rate, and future field pilots are encouraged to include observation wells in order to gain information of field-scale foam propagation. Foam strength is generally high with all gases. The exception is CO 2 at high pressure where CO 2 becomes supercritical. Stability of foam has been studied in laboratory and field tests, and has confirmed long-term stability of foam.

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“…Our high throughput foam stability screening method has already been described in other publications (Chabert et al 2013). Screening is performed here at 90°C, and the ranking is expected to be conserved at higher temperature.…”

Section: High Throughput Foam Stability Screeningmentioning

confidence: 99%

“…To prevent boiling of solutions, all experiments are carried out above water vapor pressure for a given experiment temperature. The protocol is directly inspired by the protocol used to generate dense CO 2 foams under high pressure (Chabert et al 2014). The cell is filled with surfactant formulation at a temperature between 100°C and 240°C.…”

Section: High Pressure/temperature Foam Stability Screeningmentioning

confidence: 99%

“…Compared to classical gas floods, steam foam floods are actually the only reported cases where foam was used for actual "in-depth" mobility control, with several pore volumes (PV) of steam co-injected with foaming surfactants (Hiraski 1989). The use of steam foam for conformance control in SAGD has also been proposed recently (Chen 2010) but not yet tested on field. Although conformance issues in SAGD may be solved by mechanical means such as the use of scab liners (Smith 2014) this requires that the position of the thief zone along the well be clearly identified.…”

Section: Introductionmentioning

confidence: 99%

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Design of Thermally Stable Surfactants Formulations for Steam Foam Injection

Cuenca

Lacombe

Morvan

et al. 2014

Day 1 Tue, June 10, 2014

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Steam injection is currently the most widespread method for heavy oil recovery. However, a serious limitation of this method is its energy cost due to heat losses in the reservoir. Steam foams can be used to increase the apparent viscosity of steam. Such an improvement of steam mobility control optimizes the heat distribution in the reservoir and reduces the impact of reservoir heterogeneities in order to raise oil recovery.Optimized formulations are required to generate stable steam foams in reservoir conditions. This paper presents an original workflow to design efficient combinations of surfactants for steam foam stabilization. The first step is the selection of surfactants demonstrating a good chemical stability at steam temperature, together with a good solubility. The second step consists in evaluating foam stability of these formulations at high pressure and temperature.We study the thermal stability of surfactants using anaerobic screening tests at high temperature. The chemical structure of surfactants is evaluated through quantitative NMR analysis before and after thermal treatment in various conditions (temperatures from 150 to 250°C and durations from 24h to a week). Generated data permit a better understanding of surfactants degradation mechanisms. A customized high pressure/high temperature sapphire view cell is used to investigate the impact of high temperature on the solubility of formulations and to generate foams in reservoir conditions of pressure and temperature. A custom image processing routine is used to measure foam volume as a function of time, in order to evaluate foam stability and rank formulations.We demonstrate the thermal stability of specific surfactants up to 240°C in anaerobic conditions. A strong influence of temperature on foam stability is observed. Our experiments serve as a baseline to design new formulations giving much longer foam stability at 185°C than benchmarks based on alpha olefin sulfonate (AOS) and alkyl aryl sulfonate (AAS). This paper thus aims at providing new insights on steam foam applications with the development of a dedicated surfactant selection workflow and the characterization of new steam foam formulations with improved performances.

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Impact of Surfactant Structure and Oil Saturation on the Behavior of Dense CO2 Foams in Porous Media

Cited by 10 publications

References 10 publications

Effect of temperature on foam flow in porous media

Effect of temperature on foam flow in porous media

Foam Generation, Propagation and Stability in Porous Medium

Design of Thermally Stable Surfactants Formulations for Steam Foam Injection

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