Successful Field Test of the First Ultra-Low Interfacial Tension Foam Flood

Wang, Demin; Cheng, Jiecheng; Yang, Zhenyu; Li, Qun; Wu, Wenxiang; Yu, Huiyu

doi:10.2523/72147-ms

Cited by 3 publications

(2 citation statements)

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“…So it is desirable to screen optimal chemical formulations which will display the best foaming behavior to provide better mobility control during core flood experiments. The chemical formulations were screened based on the foam stability tests as described by previous researchers (Demin et al 2001a(Demin et al , 2001bSimjoo et al 2013;Bageri et al 2014;Belhaij and Al-Mahdy 2015).…”

Section: Chemical Screening and Formulationmentioning

confidence: 99%

Enhanced oil recovery by alkaline-surfactant-alternated-gas/CO2 flooding

Phukan

Gogoi

Tiwari

2018

J Petrol Explor Prod Technol

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The volumetric sweep efficiencies of CO 2 flooding for enhanced oil recovery (EOR) are generally low due to problems of viscous fingering and gravity override. This paper attempts to study a relatively new and promising method to reduce the mobility of CO 2 flooding and increase oil recovery under reservoir conditions. Referred to as alkaline-surfactant-alternatedgas/CO 2 (ASAG) flooding, this method is essentially the synergic combination of chemical and immiscible CO 2 flooding. In this work, chemical formulations were identified through foam stability tests based on their foaming ability coefficients.The selected formulations were further tested for their capabilities to reduce oil-water interfacial tensions (IFT) to ultra-low value. With the best performing formulations, the laboratory-scale core flooding experiments were conducted to evaluate their EOR potential. The core flooding experiments were performed with sandstone reservoir core samples from two different depths of a major depleted oil field of Upper Assam Basin, India. This study reports the successful application of a natural anionic surfactant (black liquor) as a co-surfactant and foaming agent during ASAG flooding. It was observed that higher oil recovery of 14.26% original oil in place (OOIP) was obtained by surfactant-alternated-gas (SAG) flooding compared to 12.03% OOIP by immiscible CO 2 alternated with brine (WAG) flooding. The highest residual oil recovery of 20% OOIP was obtained for ASAG flooding with the alkali, surfactant and black liquor in the chemical slug. Oil recovery performances during SAG and ASAG flooding were found to be better for core samples with lower porosity-permeability due to stronger foam formation in lower permeability cores.

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Section: Chemical Screening and Formulationmentioning

confidence: 99%

Enhanced oil recovery by alkaline-surfactant-alternated-gas/CO2 flooding

Phukan

Gogoi

Tiwari

2018

J Petrol Explor Prod Technol

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“…However, the chosen foaming agent should be sustainable, nontoxic and have less environmental disadvantages especially for the offshore field applications. Many screening studies to choose proper foaming agent have been performed by many scientists (Keeling, 1984;Maini and Ma, 1984;Borchardt et al, 1985;Heller et al, 1985;Suffridge et al, 1989;Hanssen and Dalland, 1990;Borchardt and Strycker, 1997;Mannhardt et al, 1998;Syahputra et al, 2000;Demin et al, 2001;Rojas et al, 2001;Marcano et al, 2009;Andrianov et al, 2011) but most of them used various petroleum based surfactant which potentially cause many ecological problems. In the recent years some reports are provided about sustainable surfactants that indicated they are already used in petroleum industry.…”

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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Low Tension Gas Flooding as a Novel EOR Method: An Experimental and Theoretical Investigation

Jong

Nguyen

Eberle

et al. 2016

SPE Improved Oil Recovery Conference

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Low Tension Gas (LTG) flooding is a novel EOR process which can address challenging reservoir conditions such as high salinity, high temperature, and tight rock. Current process understanding is limited, and a joint experimental and modeling approach allows for both interpretation and insight into the complex interactions between the key process parameters of salinity gradient, foam strength, microemulsion phase behavior, and phase desaturation in order to achieve a physically correct and predictive process model. We performed a series of corefloods in high permeability Berea sandstones (~500 mD) to demonstrate the impact of salinity gradient on the LTG process and interactions between key mechanisms such as microemulsion phase behavior and foam stability. In order to provide additional insight into the experimental study and improve understanding of the LTG process, we used our newly developed LTG simulator which we built within CMG GEM. The results demonstrate that decreasing slug injection salinity can lead to a 15% increase in residual oil in place (ROIP) recovery over a slug injected at optimum salinity, with earlier breakthrough and steeper recovery slope. In addition, there is evidence of a late time pressure buildup as salinity is decreased through mixing with drive salinity which is indicative of increasing foam stability. This may be due to an inverse relationship between oil-water IFT and foam stability and thus designing an optimal salinity gradient for an LTG process requires balancing oil mobilization due to ultralow IFT and effectively displacing mobilized oil with adequate foam mobility control. We introduce and show the strength our compositional LTG simulator in a pioneering laboratory and simulation study that sheds light on the interaction between salinity, microemulsion phase behavior, and foam strength. Our conclusions indicate a significant departure from traditional ASP understanding and methodology when designing an LTG salinity gradient and serve as a foundation for future investigation.

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Successful Field Test of the First Ultra-Low Interfacial Tension Foam Flood

Cited by 3 publications

References 0 publications

Enhanced oil recovery by alkaline-surfactant-alternated-gas/CO2 flooding

Enhanced oil recovery by alkaline-surfactant-alternated-gas/CO2 flooding

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

Low Tension Gas Flooding as a Novel EOR Method: An Experimental and Theoretical Investigation

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