An Experimental Investigation of Effects of Surfactants on Spilling Breakers PDF Download

Author: Xinan Liu
Publisher:
ISBN:
Category : Surface active agents
Languages : en
Pages : 460

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Author: Joshua M. Borsari
Publisher:
ISBN:
Category :
Languages : en
Pages : 196

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Author:
Publisher:
ISBN:
Category : Dissertations, Academic
Languages : en
Pages : 674

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Author:
Publisher:
ISBN:
Category : Dissertation abstracts
Languages : en
Pages : 776

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Author: Miguel Mejia (M.S. in Engineering)
Publisher:
ISBN:
Category :
Languages : en
Pages : 286

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Book Description
Carbonates are important candidates for enhanced oil recovery, but recovering oil from oil-wet fractured carbonate reservoirs is challenging. Waterflooding bypasses the rock matrix and recovers little oil. Chemical enhanced oil recovery using surfactants increases oil recovery by lowering the interfacial tension, changing the wettability, and generating viscous microemulsions that improve mobility control. Seven Texas Cream Limestone cores with a permeability of 15-30 md were fractured and saturated with 100% oil. The cores were aged for one week at 78 C to make them oil-wet. The fracture permeability was adjusted so that it was 10,000 times higher than the rock matrix by changing the confining stress. Waterflooding recovered an average of 6.5% of the original oil in place with an oil cut of less than 2% at the end of the waterfloods. Aqueous surfactant-alkali solution was injected after each waterflood. All of the surfactant floods produced oil cuts of more than 25% soon after injection started. Surfactant slugs of 3 PV, 1 PV and 0.3 PV followed by brine drives recovered 45, 44, and 30% of the remaining oil after the waterfloods. The 1 PV and 0.3 PV slug sizes were more efficient in terms of oil recovered for a given mass of injected surfactant. In both cases, a high salinity surfactant solution was injected to produce a viscous microemulsion in-situ. The viscous microemulsion increased oil recovery by promoting crossflow and improving mobility control. Low surfactant retention is vital for the economics of surfactant floods. The experiments show that using sodium hydroxide caused surfactant retention to be very low in fractured limestone cores. The average surfactant retention was 0.17 mg/g-rock. Decreasing the flow rate increased the oil recovery at a given injected pore volume. Thus changing practical design variables (salinity, surfactant slug size, flow rate) has a significant effect on oil recovery

Author: M. L. Banner
Publisher:
ISBN:
Category : Ocean waves
Languages : en
Pages : 478

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Author: Chong-hu Shen
Publisher:
ISBN:
Category : Oil field flooding
Languages : en
Pages : 238

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Author: Mark W. D. Grattan
Publisher:
ISBN:
Category :
Languages : en
Pages :

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Author: Josephine Sum
Publisher:
ISBN:
Category :
Languages : en
Pages : 160

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Book Description

Author: Vahideh Mirchi
Publisher:
ISBN: 9780438886384
Category : Enhanced oil recovery
Languages : en
Pages : 181

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Book Description
This study aims at establishing structure-function relationships relevant to surfactant-based enhanced oil recovery (EOR) under different wettability conditions. We present the results of an extensive, multi-scale experimental study designed to probe the effects of surfactant molecular structure on oil displacement in sandstone and carbonate rock samples. Initially a new framework was developed to methodically characterize the effect of surfactants on fundamental parameters governing fluid displacement in brine/oil/tight rock systems at reservoir conditions. For that, we present a detailed methodology for measuring the interfacial properties of these systems, including rock substrate preparation, thin needle utilization, fluid pre-equilibration, in-line density measurements, all of which are critically important due to surfactant partitioning in brine and oil phases. The experimental framework was first validated with simple ultra-low IFT systems using the rising/captive bubble technique, then the effect of pressure, temperature, surfactant concentration, and brine chemistry on IFT and CA were investigated in a systematic manner. Subsequently, the framework was used to examine the effect of hydrophobic and hydrophilic chain lengths of polyoxyethylenated nonionic surfactants on dynamic interfacial properties in porous media. It included comprehensive experimental examination of phase behavior, cloud point temperature, dynamic interfacial tension, dynamic contact angle, and spontaneous and forced imbibitions at ambient and reservoir conditions. This resulted in development of a new insight that relates the speed by which surfactants reduce interfacial tension to oil-brine displacement efficiency. This relationship was reconfirmed by examining pore-fluid occupancies generated through surfactant imbibition in micromodels. In order to directly study pore-level fluid distributions as a function of surfactant structure, a state-of-the-art X-ray micro-CT scanner integrated with a miniature core-flooding apparatus was deployed to generate three-dimensional pore-fluid occupancy maps at the pore scale. The core-flooding results revealed that there is an additional set of factors besides pore geometry, rock surface wettability, fluid-fluid interfacial tension, and fluids’ viscosities, densities, and flow rates that directly contributes to the distribution of fluids at the pore scale. We demonstrate that under similar rock and fluid properties, interfacial repulsive and attractive interactions, caused by the adsorption of surface-active chemicals on fluid-fluid interfaces, can significantly alter pore-scale fluid occupancies. Oil cluster analyses along with three-dimensional (3D) visualization of fluid distributions indicate that using the nonionic surfactant with large head instead of the anionic surfactant with small head results in the breaking up of the large and medium oil clusters into smaller and scattered ones. We propose a mechanism relating the stability of oil-brine interface to surfactant structure that is responsible for the break-up and/or coalescence of oil clusters inside the pore space. The suggested mechanism is confirmed by the micro-CT images and associated oil cluster analyses. This phenomenon affects the competition between the frequency of displacement mechanisms causing variations in remaining oil saturations. Using the same microtomography technique, we developed a significantly-improved understanding of pore-level displacement mechanisms during low-salinity surfactant flooding in oil-wet carbonates. In this contribution, in-situ fluid distribution maps, in-situ contact angles, and thicknesses of wetting oil layers were investigated under different brine salinities in the presence and absence of a cationic surfactant at elevated pressure and temperature conditions. The investigation revealed that enhanced oil production during low-salinity surfactant waterflooding is caused by several factors such as a rapid alteration of in-situ contact angles toward neutral-wet state, layer thinning of the oil phase, and an increase in the contribution of small-sized pores to the total oil production. The wettability reversal was more profound when the surfactant injection was succeeding a low-salinity waterflooding. The insights gained in this work using different surfactant molecular structures, rock types, brine salinities, and wettability conditions have direct implications for the design of more effective surfactant-based EOR projects.