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Author

Aly A. Hamouda

Other affiliations: Phillips Petroleum Company
Bio: Aly A. Hamouda is an academic researcher from University of Stavanger. The author has contributed to research in topics: Adsorption & Calcite. The author has an hindex of 25, co-authored 66 publications receiving 1813 citations. Previous affiliations of Aly A. Hamouda include Phillips Petroleum Company.


Papers
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Journal ArticleDOI
TL;DR: In this article, the authors show that long chain fatty acid (stearic acid) strongly adsorbs onto the calcite surface from n-C10 in oil/water/calcite system as indicated by contact angle measurements.

185 citations

Journal ArticleDOI
TL;DR: In this article, the authors compared conservative level set method (LSM) and Cahn-Hilliard phase field method (PFM) in modeling 2D two-phase flow through porous media, based on their ability to capture different phenomena associated with the medium permeability and fluid viscosity contrasts.

136 citations

Journal ArticleDOI
15 May 2006
TL;DR: TheEnthalpy versus coverage curve for water adsorption and its comparison to liquefaction enthalpy is shown to be a meaningful method for characterizing the wettability of a surface.
Abstract: The effect of long-chain fatty acid adsorption on the wetting states of calcite and mica powders is investigated. The selected long-chain fatty acids are saturated or unsaturated aliphatic acids (stearic acid and oleic acid, respectively) and naphthenic acids with saturated or unsaturated aromatic rings (18-cyclohexyloctadecanoic acid and 18-phenoloctadecanoic acid, respectively). The amount of irreversibly adsorbed acid is determined by thermogravimetric analysis. The affinity of water and n-decane for these samples before and after modification is deduced from their adsorption isotherm and microcalorimetry. Thermodynamic analysis of surface pressure and spreading tension are performed based on adsorption isotherms. The enthalpy versus coverage curve for water adsorption and its comparison to liquefaction enthalpy is shown to be a meaningful method for characterizing the wettability of a surface. The naphthenic acid with unsaturated aromatic ring deeply modifies the calcite to an oil-wet state. The mica powder was not as strongly modified as calcite by these acid molecules.

111 citations

Journal ArticleDOI
TL;DR: In this article, the authors investigated extreme cases with ion-free water and water containing Mg2+ or SO42- and found that the initial fluid in contact with the carbonate rock before the drainage process showed the highest oil recovery when Mg 2+ is present in the imbibing fluids.
Abstract: Oil recovery by an imbibition process at elevated temperatures depends not only on fluid composition but also on the history of the process, that is, the composition of the initial fluid in contact with the carbonate rock before the drainage process. In this work, extreme cases have been investigated with ion-free water and water containing Mg2+ or SO42-. Modified carbonate rocks with stearic acid that was initially saturated with ion-free water followed by an imbibition process with fluids containing Mg2+ or SO42-, at the same concentration as the injected seawater, shows the highest oil recovery when Mg2+ is present in the imbibing fluids. Whereas the initially saturated fluid and imbibing fluids contain SO42-, an inconsiderable difference between the oil recovery factor with SO42- and that for the ion-free water was observed. This is in contrast to Mg2+-containing imbibing fluid, which showed the lowest recovery. Computation of the disjoining pressure for the three systems (ion-free water, SO42-, and M...

98 citations


Cited by
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01 Jan 2016

1,715 citations

Journal ArticleDOI
TL;DR: In this paper, anionic surfactant solutions are evaluated for enhancing oil recovery by spontaneous imbibition from oil-wet carbonate rocks, and the ease of wettability alteration is a function of the aging time and temperature and the surfactants formulation.
Abstract: Oil recovery by waterflooding in fractured formations is often dependent on spontaneous imbibition. However, spontaneous imbibition is often insignificant in oil-wet, carbonate rocks. Sodium carbonate and anionic surfactant solutions are evaluated for enhancing oil recovery by spontaneous imbibition from oil-wet carbonate rocks. Crude-oil samples must be free of surface-active contaminants to be representative of the reservoir. Calcite, which is normally positively charged, can be made negative with sodium carbonate. The ease of wettability alteration is a function of the aging time and temperature and the surfactant formulation.

520 citations

Journal ArticleDOI
TL;DR: A fundamental study of the deposition and aging of a thin incipient wax-oil gel that is formed during the flow of waxy oils in cooled pipes was performed in this article.
Abstract: A fundamental study of the deposition and aging of a thin incipient wax-oil gel that is formed during the flow of waxy oils in cooled pipes was performed. The solubility of high molecular weight paraffins in naphthenic, aromatic or paraffinic solvents is very low and decreases rapidly with decreasing temperature. This property of the paraffins leads to the formation of gels of complex morphology that deposit on the cold walls of the subsea pipelines during the flow of waxy crudes. This deposition reduces the pipe diameter and decreases the flow capacity of the pipe. These wax-oil gels contain a large fraction of oil trapped in a 3-D network structure of the wax crystals that behaves as a porous medium. After the incipient gel is formed, wax molecules continue to diffuse into this structure, thereby increasing its wax content. A model system of wax and oil mixture was used to understand the aging process of the wax-oil gels, which hardens the wax deposit with time. To understand the physics of the aging process for incipient thin-film deposits, a series of laboratory flow loop experiments was performed. The aging process was a counterdiffusion phenomenon with a critical carbon number above which wax molecules diffuse into the gel deposit and below which oil molecules diffuse out of the deposit. The aging rate of the gel deposit depends on the oil flow rate and the wall temperature. A mathematical model developed predicted the growth and wax content of the gel deposit on externally cooled pipe walls. The theory agreed with experiments excellently for thin gels.

431 citations

Journal ArticleDOI
TL;DR: In this article, the authors investigated how water chemistry affects surface charge and rock dissolution in a pure calcium carbonate rock similar to the Stevns Klint chalk by constructing and applying a chemical model that couples bulk aqueous and surface chemistry.
Abstract: Water chemistry has been shown experimentally to affect the stability of water films and the sorption of organic oil components on mineral surfaces. When oil is displaced by water, water chemistry has been shown to impact oil recovery. At least two mechanisms could account for these effects, the water chemistry could change the charge on the rock surface and affect the rock wettability, and/or changes in the water chemistry could dissolve rock minerals and affect the rock wettability. The explanations need not be the same for oil displacement of water as for water imbibition and displacement of oil. This article investigates how water chemistry affects surface charge and rock dissolution in a pure calcium carbonate rock similar to the Stevns Klint chalk by constructing and applying a chemical model that couples bulk aqueous and surface chemistry and also addresses mineral precipitation and dissolution. We perform calculations for seawater and formation water for temperatures between 70 and 130°C. The model we construct accurately predicts the surface potential of calcite and the adsorption of sulfate ions from the pore water. The surface potential changes are not able to explain the observed changes in oil recovery caused by changes in pore water chemistry or temperature. On the other hand, chemical dissolution of calcite has the experimentally observed chemical and temperature dependence and could account for the experimental recovery systematics. Based on this preliminary analysis, we conclude that although surface potential may explain some aspects of the existing spontaneous imbibitions data set, mineral dissolution appears to be the controlling factor.

428 citations

Journal ArticleDOI
TL;DR: In this paper, a detailed analysis of the available literature data on breakthrough pressure measurements in caprock samples confirms the existence of a wettability alteration by dense CO2, both in shaly and in evaporitic caprocks.
Abstract: One of the critical factors that control the efficiency of CO2 geological storage process in aquifers and hydrocarbon reservoirs is the capillary-sealing potential of the caprock. This potential can be expressed in terms of the maximum reservoir overpressure that the brine-saturated caprock can sustain, i.e. of the CO2 capillary entry pressure. It is controlled by the brine/CO2 interfacial tension, the water-wettability of caprock minerals, and the pore size distribution within the caprock. By means of contact angle measurements, experimental evidence was obtained showing that the water-wettability of mica and quartz is altered in the presence of CO2 under pressures typical of geological storage conditions. The alteration is more pronounced in the case of mica. Both minerals are representative of shaly caprocks and are strongly water-wet in the presence of hydrocarbons. A careful analysis of the available literature data on breakthrough pressure measurements in caprock samples confirms the existence of a wettability alteration by dense CO2, both in shaly and in evaporitic caprocks. The consequences of this effect on the maximum CO2 storage pressure and on CO2 storage capacity in the underground reservoir are discussed. For hydrocarbon reservoirs that were initially close to capillary leakage, the maximum allowable CO2 storage pressure is only a fraction of the initial reservoir pressure.

407 citations