Effects of Foam Quality and Flow Rate on CO2-Foam Behavior at Reservoir Temperature and Pressure

Chang, Shih-Hsien; Grigg, Reid B.

doi:10.2118/56856-pa

Cited by 62 publications

(39 citation statements)

References 29 publications

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“…These studies show that a certain range of foam quality exists within which foam is able to reduce mobility and this range depends on chemical and fluid properties, rock properties, as well as injection methodology and rates. Several authors have reported the mobility reducing range to be between 40 to 95% foam qualities [9,21].…”

Section: Foam Qualitymentioning

confidence: 99%

Stability and texture of CO 2 /N 2 foam in sandstone

Siddiqui

Gajbhiye

2017

Colloids and Surfaces A: Physicochemical and Engineering Aspect

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Section: Foam Qualitymentioning

confidence: 99%

Stability and texture of CO 2 /N 2 foam in sandstone

Siddiqui

Gajbhiye

2017

Colloids and Surfaces A: Physicochemical and Engineering Aspect

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“…As a result, sweep efficiency decreases and significant amounts of oil are left behind (Chang and Grigg, 1999;Apaydin and Kovscek, 2001;Panahi, 2004;Le et al, 2008).…”

Section: Introductionmentioning

confidence: 99%

Application of Sustainable Foaming Agents to Control the Mobility of Carbon Dioxide in Enhanced Oil Recovery

2012

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Carbon dioxide (CO 2 ) flooding is a conventional process in which the CO 2 is injected into the oil reservoir to increase the quantity of extracting oil. This process also controls the amount of released CO 2 as a greenhouse gas in the atmosphere which is known as CO 2 sequestration process. However, the mobility of the CO 2 inside the hydrocarbon reservoir is higher than the crude oil and always viscous fingering and gravity override problems occur during a CO 2 injection. The most common method to overcome these problems is to trap the gas bubbles in the liquid phase in form of aqueous foam prior to CO 2 injection. Although, the aqueous foams are not thermodynamically stable, the special care should be considered to ensure about bulk foam preparation and stability. Selection of a proper foaming agent from a large number of available surfactants is the main step in the bulk foam preparation. To meet this purpose, many chemical and crude oil based surfactants have been reported but most of them are not sustainable and have disposal problems. The objective of this experimental study is to employ Lingosulfonate and Alkyl Polyglucosides (APGs) as two sustainable foaming agents for the bulk foam stability investigations and foam flooding performance in porous media. In the initial part, the bulk foam stability results showed that APGs provided more stable foams in compare with Lingosulfonate in all surfactant concentrations. In the second part, the results indicated that the bulk foam stability measurements provide a good indication of foam mobility in porous media. The foaming agent's concentration which provided the maximum foam stability also gave the highest value of mobility reduction in porous media.

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“…During the WAG process, water can reduce the mobility of CO 2 ; it can also trap oil, increase water flow, and decrease the extraction of hydrocarbons from oil by CO 2 (Bernard et al 1980). Besides the water-alternating-gas (WAG) process, the dispersion of CO 2 in water with a suitable foaming agent (surfactant) has been considered as an alternative to reduce CO 2 mobility (Chang and Grigg, 1999;Khalil and Asghari, 2006;Yin et al 2009). In this method, a foaming agent (surfactant) is injected along with CO 2 in the reservoir.…”

Section: Introductionmentioning

confidence: 99%

“…In this method, a foaming agent (surfactant) is injected along with CO 2 in the reservoir. Foam formed by either co-injecting CO 2 and/or alternating with a suitable aqueous foaming agent (Lee et al 1991;Chang and Grigg, 1999) consists of CO 2 macroscopically dispersed in the brine phase. This has an apparent viscosity several orders of magnitude greater than the viscosity of either phase in the dispersion, even at very low foaming agent concentrations (Tabatabal et al 1993).…”

Section: Introductionmentioning

confidence: 99%

“…For any CO 2 -foam project, there are many challenges that must be met. These include finding a suitable foaming agent (surfactant) with low retention, propagation profiles of the foaming agent, concentration of the surfactant and the qualities of foam to be injected (Chang and Grigg, 1999). The retention of the surfactants on the reservoir minerals may destabilize the dispersion and reduce the effectiveness of the CO 2 -foam process (Green and Willhite, 1998;Mannhardt and Novosad, 1994).…”

Section: Introductionmentioning

confidence: 99%

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Retention of CO2-Foaming Agent in CO2-Foam Flooding of Heterogeneous Carbonate Reservoirs

2011

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The efficiency of carbon dioxide (CO 2 )-flooding in highly heterogeneous reservoirs may be low due to poor macroscopic sweep. One of the possible ways to increase macroscopic sweep efficiency is by reducing the CO 2 mobility by foam. Retention of the foaming agent during CO 2 -foam flooding is an important aspect affecting both technical and economical potential of the process. This paper presents both experimental and numerical simulation studies performed to investigate the retention of CO 2 -foaming agents in heterogeneous carbonate reservoirs. These reservoir types consist of high permeable "thief zones" -fractures or high permeable layers and the rest of the reservoir -matrix or low permeable layers. The retention of CO 2 -foaming agent was studied in flow-through laboratory experiments with CO 2 -foaming agents; branched ethoxylated sulphonates with different ethoxylation degree in outcrop Liege chalk rock at 55 o C. The retention of the foaming agents was determined by breakthrough curves based on chromatographic separation between the foaming agent and a tracer. The flow-through retention experiments were reproduced in a numerical simulator. The results indicate that the retention (the amount of foaming agent lost per rock weight) depends on the type of foaming agent and oil saturation. It is concluded based on simulation results that the amount of the foaming agents retained in heterogeneous reservoirs would strongly depend on its transfer mechanism from high into low permeable zones. The diffusion process is slow and therefore the foaming agent might penetrate only into a certain fraction of the matrix blocks or low permeability layers during the project life time. The retention of the foaming agent in these heterogeneous carbonate reservoirs may therefore be much lower than estimated based on viscous floods. A numerical model describing diffusion and retention by adsorption was established. A good match between experimental and modeling results was obtained without individually tuning the numerical model for each specific experiment. Additional simulation results showed that on the field scale the amount of foaming agent retained in heterogeneous reservoirs will depend on the number of high permeable zones and the size of the matrix blocks.

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Effects of Foam Quality and Flow Rate on CO2-Foam Behavior at Reservoir Temperature and Pressure

Cited by 62 publications

References 29 publications

Stability and texture of CO 2 /N 2 foam in sandstone

Stability and texture of CO 2 /N 2 foam in sandstone

Application of Sustainable Foaming Agents to Control the Mobility of Carbon Dioxide in Enhanced Oil Recovery

Retention of CO2-Foaming Agent in CO2-Foam Flooding of Heterogeneous Carbonate Reservoirs

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