Investigation into the Processes Responsible for Heavy Oil Recovery by Alkali-Surfactant Flooding

Bryan, J.; Thuy, An; Kantzas, Apostolos

doi:10.2118/113993-ms

Cited by 62 publications

(33 citation statements)

References 37 publications

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“…Recovery in chemical flooding of heavy-oil reservoirs have been shown to depend on flow rate, and consequently on the shear rate [5][6][7][8][9][10]. This is consistent with capillary number dependencies associated with emulsion flow [11].…”

Section: Evidence Of Emulsions Conformance Effects: Heavy-oil Eorsupporting

confidence: 66%

“…The issue of mobility ratio or control arises because viscous water has much lower viscosity than heavy oil and consequently the displacement front develops fingers and oil recovery is generally poor. Alkali-surfactant (AS) flooding has been shown to be a potential viable technology for EOR in heavy-oil reservoirs [5][6][7][8][9][10]. However, in the absence of a thickening agent such as polymers, the increase in water saturation as water displaces oil only worsens the mobility control issue.…”

Section: Evidence Of Emulsions Conformance Effects: Heavy-oil Eormentioning

confidence: 99%

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Stability Proxies for Water-in-Oil Emulsions and Implications in Aqueous-based Enhanced Oil Recovery

2011

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Several researchers have proposed that mobility control mechanisms can positively contribute to oil recovery in the case of emulsions generated in Enhanced-Oil Recovery (EOR) operations. Chemical EOR techniques that use alkaline components or/and surfactants are known to produce undesirable emulsions that create operational problems and are difficult to break. Other water-based methods have been less studied in this sense. EOR processes such as polymer flooding and LoSal TM injection require adjustments of water chemistry, mainly by lowering the ionic strength of the solution or by decreasing hardness. The decreased ionic strength of EOR solutions can give rise to more stable water-in-oil emulsions, which are speculated to improve mobility ratio between the injectant and the displaced oil. The first step toward understanding the connection between the emulsions and EOR mechanisms is to show that EOR conditions, such as salinity and hardness requirements, among others, are conducive to stabilizing emulsions. In order to do this, adequate stability proxies are required. This paper reviews commonly used emulsion stability proxies and explains the advantages and disadvantage of methods reviewed. This paper also reviews aqueous-based EOR processes with focus on heavy oil to contextualize in-situ emulsion stabilization conditions. This context sets the basis for comparison of emulsion stability proxies.

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Section: Evidence Of Emulsions Conformance Effects: Heavy-oil Eorsupporting

confidence: 66%

Section: Evidence Of Emulsions Conformance Effects: Heavy-oil Eormentioning

confidence: 99%

Stability Proxies for Water-in-Oil Emulsions and Implications in Aqueous-based Enhanced Oil Recovery

2011

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“…In these systems, which were expected to form only W/O emulsions, there was no difference between the response from high vs. low permeability cores in Table 5. This could potentially be an indication of wettability alteration (52) , but in general, it can be concluded that these emulsions are equally effective in all permeabilities for plugging off the water channels and providing improved sweep in the core. Thus, AS flooding is not only possible in reservoirs where fresh water is not available, but, in fact, may be more stable than fresh water chemical floods.…”

Section: Core Flood Experimentsmentioning

confidence: 99%

Insights Into Non-Thermal Recovery of Heavy Oil

Mai

Bryan

Goodarzi

et al. 2009

Journal of Canadian Petroleum Technology

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106

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Many heavy oil reservoirs contain oil that has some limited mobility under reservoir conditions. In these reservoirs, a small fraction of the oil-in-place can be recovered using the internal reservoir energy through heavy oil solution gas drive (primary production). An integral part of this process is the so-called 'foamy oil mechanism', whereby oil is produced as a gas-in-oil dispersion. At the end of primary production, the bulk of the oil is still in place, while the natural energy of the reservoir has been depleted. This remaining oil is still mostly continuous and presents a valuable target for further recovery. Many of these reservoirs are relatively small or thin, or may be contacted by overlying gas or underlying water. As such, they are poor candidates for thermal oil recovery methods, so any additional oil recovery after primary production must be non-thermal. In this work, we present experimental results of foamy oil depletion at two different length scales and varying depletion rates. Tests were conducted in the absence of sand production, and the results from the depletion experiments are interpreted in terms of viscous forces. At the conclusion of primary recovery, the potential for further non-thermal exploitation of these reservoirs is explored. Results for waterflooding and chemical flooding are presented, demonstrating the viability of these techniques for heavy oil EOR. Several displacement mechanisms are identified through the secondary and tertiary processes that contribute to significant (although potentially slow) incremental recovery of heavy oil. Introduction Many countries have heavy oil reservoirs. Canada and Venezuela in particular contain some of the largest heavy oil and bitumen resources in the world. Rising energy demands, coupled with a decline in conventional oil reserves, has led to increased interest in heavy oil recovery in recent years. The size of these heavy oil deposits is considerable, and with volatile crude oil prices making it difficult to produce from some higher viscosity bitumen reservoirs, production of heavy oil could potentially be very important in years to come. Understanding the mechanisms by which heavy oil can be displaced in reservoirs is crucial to the successful recovery of this resource base. Heavy oil can be defined as a class of oils with viscosity ranging from 50 mPa.s up to around 50,000 mPa.s. This oil has limited mobility under reservoir temperature and pressure, and Darcy's Law predicts that the oil can flow slowly under high applied pressure gradients. However, it has been observed that in these reservoirs, solution gas drive leads to significantly higher rates and recoveries than what was expected by conventional understanding of gas-oil relative permeability behaviour(1). This behaviour, first reported in Canadian heavy oil, has since been observed in many other reservoirs around the world including South America, China and Albania. Investigations into the causes of this abnormal, but fortuitous, primary production response have been the focus of many publications in the past 25 years. The recovery from primary production in heavy oil reservoirs may be as high as 20%(2), but is usually lower.

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“…Alkali-surfactant-polymer flooding can allow operators to extend reservoir pool life and extract incremental reserves recently inaccessible by conventional EOR methods such as waterflooding (Jia et al, 2005). Chemical surfactants use to decrease the IFT between liquid and liquid phase, making the immobile oil mobile (Touhami et al, 1998;Bryan et al, 2008). Alkali decreases adsorption of the surfactant on the solid surfaces and reacts with acidic substances in the oil to form new surfactant.…”

Section: Microemulsion Floodingmentioning

confidence: 99%

Utilization of Surfactant Flooding Processes for Enhanced Oil Recovery (EOR)

Demirbas

Alsulami

Hassanein

2015

Petroleum Science and Technology

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Surfactant flooding is a well-known enhanced oil recovery (EOR) technique that has been used worldwide for decades. The surfactant can meaningful lower interfacial tension and change the wetting properties. Surfactant related recovery processes are of increasing interest and importance because of high oil prices and the urge to meet energy demand. The water flooding methods include chemical flooding and low-salinity water (LSW) flooding. Chemical flooding methods have been developed to recover residual oil trapped after conventional oil recovery is getting important recovery. The LSW flooding includes injecting brine with a lower content of salt or ionic strength. Water flooding improves oil recovery by displacing oil, and injection water is usually taken from the nearest available source. The injected alkali and surfactant, so that the interfacial tension between oil and water is lowered and thus residual oil can move. There is a relationship among chemical EOR efficiency and fluid viscosity, relative permeability, interfacial tension, wettability, and capillary pressure. The polymer increases the viscosity of the flooding water, reduces water mobility, and thus greatly reduces oil flow ratio so to reduce water flooding fingering, improve horizontal and microscopic pore structure reservoir heterogeneity condition, relieve channeling flow around other phenomena, and increase the flooding swept volume of water.

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Investigation into the Processes Responsible for Heavy Oil Recovery by Alkali-Surfactant Flooding

Cited by 62 publications

References 37 publications

Stability Proxies for Water-in-Oil Emulsions and Implications in Aqueous-based Enhanced Oil Recovery

Stability Proxies for Water-in-Oil Emulsions and Implications in Aqueous-based Enhanced Oil Recovery

Insights Into Non-Thermal Recovery of Heavy Oil

Utilization of Surfactant Flooding Processes for Enhanced Oil Recovery (EOR)

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