Application In Oil Reservoirs Research Articles

Synthesis and thermal analysis of hydrophobic iron oxide nanoparticles for improving in-situ combustion efficiency of heavy oils

Hydrophobic iron oxide nanoparticles (NPs) were synthesized for the oil reservoir application. Their suspensions in crude oils were subjected to thermogravimetric analysis, and kinetic model of different oxidation steps was obtained by a modified dynamic activation energy model. Results showed that NPs catalyzed initial oxygenation reactions, upgrading efficiency of cracking step, and speeded up the propagation of the combustion front. Hence, their dispersion near wellbore could increase quality of the produced oil, fuel availability, and propagation rate of the combustion front, by reducing plugging risk of pore throats and deactivation risk of fixed bed catalysts.

Shape- and size-controlled superparamagnetic iron oxide nanoparticles using various reducing agents and their relaxometric properties by Xigo acorn area

Superparamagnetic iron oxide nanoparticles (SPIONs) were investigated owing to their potential relaxometric properties for magnetic resonance imaging (MRI) applications. For this purpose, shape- and size-controlled SPIONs were prepared using various reducing agents via a facile chemical coprecipitation method. The optimization of reaction parameters such as stirring rate, temperature, reaction time, and pH was carried out to study the particle’s growth, size, and shape of nanoparticles (NPs). Transmission electron microscopy (TEM) images reveal that the spherical (9.1 ± 1.5 nm)- and cubic (11.7 ± 1.8 nm)-shaped NPs were attained using NH4OH and NaOH as reducing agents, respectively. X-ray diffraction (XRD) analysis of as-synthesized SPIONs shows the formation of magnetite (Fe3O4) phase having cubic inverse spinel structure. The various oxidation states of Fe were investigated via X-ray photoelectron spectroscopy (XPS) by analyzing Fe 2p spectra of SPIONs. The magnetic character and chemical stability of SPIONs were monitored in the synthetic seawater (SW) having salinity 36.03 g L−1; which is the critical requirement for oil reservoir applications. Spin–spin (T2) relaxation signals were attained using miniaturized Acorn Area analyzer to determine the relaxometric properties. The transverse relaxivities (r2) for MNP–NH4OH (41.0 mM−1 s−1) and MNP–NaOH (28.5 mM−1 s−1) were 2.11 and 1.47 times higher than MNP–KOH (19.4 mM−1 s−1), respectively. This study affirms that by controlling the reaction parameters, we can selectively design Fe3O4 NPs of desired size and shape, which give enhanced T2-relaxation and excellent relaxivity properties in SW for potential MRI applications associated with oil reservoirs.

Colloidal solution of luminescent ZnO quantum dots embedded silica as nano-tracers for remote sensing applications

The deployment of traditional radioactive isotopes as tracers has the drawback of environmental concerns. In this study, we investigated alternative luminescent zinc oxide quantum dots embedded silica (ZnO@SiO2) nanoparticles as tracers for oil reservoir applications. ZnO quantum dots (QDs) were prepared via solgel process having an average diameter of ~5 nm. For the encapsulation of these ZnO QDs, tetraethyl orthosilicate (TEOS) was utilized to synthesize hydrophilic ZnO@SiO2 nanoparticles (H-NPs), while dimethyldiethoxysilane (DMDES) in combination with TEOS was used to prepare partially hydrophobic ZnO@SiO2 (PH-NPs). The fluorescence of bare ZnO QDs was compared to that of silica-coated ZnO@SiO2 NPs in various solvents. The effects of cetyltrimethylammonium bromide (CTAB) surfactant and silica coatings on the fluorescence of ZnO QDs were investigated by photoluminescence spectroscopy. The fluorescence and structural properties of ZnO@SiO2 nano-tracers were examined in highly saline water and at elevated temperature to mimic the oil reservoir environment. The significant improvement in fluorescence emission stability was achieved for PH-NPs in harsh conditions, which advocates their potential use as a tracer material for oil exploration.

Synthesis, characterization, and relaxometry studies of hydrophilic and hydrophobic superparamagnetic Fe3O4 nanoparticles for oil reservoir applications

Information acquisition and fluid characterization of oil reservoirs are one of the most challenging and scientifically demanding areas in the oil exploration industry. Herein, we report a single-step solvothermal method for the synthesis of highly-stable hydrophilic and hydrophobic superparamagnetic iron oxide nanoparticles (SPIONs). The functionalization of SPIONs was achieved using polyethylene glycol (PEG-400) and oleylamine (OLA) for water/oil phases of the reservoir, respectively. For comparison, uncoated SPIONs were also prepared by coprecipitation. Stability of hydrophilic SPIONs was monitored in deionized (DI) water and artificial seawater (ASW), while stability of hydrophobic SPIONs was investigated in model oil (cyclohexane-hexadecane 1:1). Several physicochemical techniques were utilized to characterize the phase and functionalization of SPIONs. Transmission electron microscopy (TEM) images display the spherical shape nanoparticles (NPs) having particle diameters 11.6 ± 1.4, 12.7 ± 2.2, and 9.1 ± 3.0 nm for PEG-Fe3O4, OLA-Fe3O4, and Fe3O4, respectively. Spin-spin (T2) relaxation measurements were performed by an Acorn Area analyzer to demonstrate contrasting ability of the contrast agents. The transverse relaxivity (r2) values for PEG-Fe3O4 (66.7 mM−1 s−1) and OLA-Fe3O4 (49.0 mM−1 s−1) were 2.07 and 1.53 times higher than Fe3O4 (32.2 mM−1 s−1) NPs, respectively. The (i) enhanced NMR T2-relaxation with optimum SPIONs concentration, (ii) excellent relaxivity properties due to their ultra-small size, and (iii) long-term stability in various continuous phases, suggest them to be promising T2-contrast agents for oil reservoir applications.

Investigation of synergistic effect of nanoparticle and surfactant in macro emulsion based EOR application in oil reservoirs

The present paper deals with the characterization of oil in water (O/W) emulsion stabilized by the synergistic effect of surfactant and nanoparticle for their application in enhanced oil recovery (EOR). The emulsions have been formulated using n-decane and paraffin oil, silica nanoparticle and two different surfactants, viz., anionic sodium dodecyl sulfate (SDS) and cationic cetyl trimethyl ammonium bromide (CTAB). The nanoparticle shows a synergetic effect in presence of surfactants which prevents the coalescence of dispersed oil droplets and lowers the interfacial tension (IFT) at the oil-water interface. The stability of emulsions was evaluated by particle size distribution, creaming behaviour, zeta potential and phase behaviour. The viscosity of emulsions remains stable at wide range temperature indicating thermal stability. The viscoelastic study indicates that the emulsions behave as a gel-like structure with a higher value of storage modulus (G′) than loss modulus (G″). The addition of polymer leads to improvement in viscosity and stability of the emulsion, proving its usefulness in the reservoir for recovery of heavy oil.

Novel Insights Into Mechanisms of Oil Recovery by Use of Low-Salinity-Water Injection

Summary The underlying mechanism of oil recovery by low-salinity-water injection (LSWI) is still unknown. It would, therefore, be difficult to predict the performance of reservoirs under LSWI. A number of mechanisms have been proposed in the literature, but these are controversial and have largely ignored crucial fluid/fluid interactions. Our direct-flow-visualization investigations (Emadi and Sohrabi 2013) have revealed that a physical phenomenon takes place when certain crude oils are contacted by low-salinity water, leading to a spontaneous formation of micelles that can be seen in the form of microdispersions in the oil phase. In this paper, we present the results of a comprehensive study that includes experiments at different scales designed to systematically investigate the role of the observed crude-oil/brine interaction and micelle formation in the process of oil recovery by LSWI. The experiments include direct-flow (micromodel) visualization, crude-oil characterization, coreflooding, and spontaneous-imbibition experiments. We establish a clear link between the formation of these micelles, the natural surface-active components of crude oil, and the improvement in oil recovery because of LSWI. We present the results of a series of spontaneous- and forced-imbibition experiments carefully designed with reservoir cores to investigate the role of the microdispersions in wettability alteration and oil recovery. To further assess the significance of this mechanism, in a separate exercise, we eliminate the effect of clay by performing an LSWI experiment in a clay-free core. Absence of clay minerals is expected to significantly reduce the influence of the previously proposed mechanisms for oil recovery by LSWI. Nevertheless, we observe significant additional oil recovery compared with high-salinity-water injection (HSWI) in the clay-free porous medium. The additional oil recovery is attributed to the formation of micelles stemming from the crude-oil/brine-interaction mechanism described in this work and our previous related publications. Compositional analyses of the oil produced during this coreflood experiment indicate that the natural surface-active compounds of the crude oil had been desorbed from the rock surfaces during the LSWI period of the experiment when the additional oil was produced. The results of this study present new insights into the fundamental mechanisms involved in oil recovery by LSWI and new criteria for evaluating the potential of LSWI for application in oil reservoirs. The fluid/fluid interactions revealed in this research can be applied to oil recovery from both sandstone and carbonate oil reservoirs because they are mainly derived from fluid/fluid interactions that control wettability alteration in both sandstone and carbonate rocks.

New Passive Water Tracers for Oil Field Applications

We present the results of theoretical and experimental work on the development of new chemical passive water tracers for application in oil reservoirs. Fluorinated benzoic acids (FBAs) are currently used as chemical water tracers in oil field applications, and they were considered as “reference water tracers” in this study. The 15 newly proposed tracer molecules are halogenated derivatives of benzoic acid that are commercially available and have two halogenated substituents on the aromatic ring, either one fluorine (F) and one trifluoromethyl group (CF3) or one fluorine (F) and one chlorine (Cl). Laboratory-scale experiments were conducted to evaluate the physicochemical properties (e.g., detection, stability, and toxicity) and performance of the molecules as potential water tracers. Both the new tracers and FBAs are simultaneously detectable using the same rapid analytical tool [ultrahigh-performance liquid chromatography coupled with tandem mass spectrometry (UHPLC/MS–MS)] and can therefore be used in t...

Aggregation behavior of a water‐soluble terpolymer with vinyl biphenyl characterized by a fluorescent probe

AbstractA terpolymer (PAAP) of acrylamide, sodium 2‐acrylamido‐2‐methylpropane sulfonate, and vinyl biphenyl as a hydrophobic monomer was synthesized to obtain a polymeric oil‐flooding agent with low molecular weight and application in oil reservoirs with medium to low permeability. The intermolecular self‐assembling mechanisms in the PAAP solutions were investigated with a pyrene fluorescence probe as functions of the polymer concentration, surfactant, and temperature. The hydrophobically associating morphologies of PAAP in an unsalted solution were observed with scanning electron microscopy. The results show that the high solution viscosity of PAAP was due to the strong intermolecular hydrophobic associations of the biphenyl groups, and the critical association concentration was 0.05 g/dL for the unsalted and brine PAAP solutions. The nonpolarity and association degree in the hydrophobic microdomains were greatly influenced by the polymer concentration. With the addition of the optimum sodium dodecyl benzene sulfonate concentration, the interpolymer hydrophobic associations were strengthened remarkably via the connection of the surfactant with biphenyl groups from different polymer chains. The number and sizes of the aggregates increased in the range of 20–50°C. These results demonstrate that the thickening effect of the PAAP polymer in the aqueous solution was due to intermolecular associations of the biphenyl groups. © 2009 Wiley Periodicals, Inc. J Appl Polym Sci, 2010

A New Polymer Application for North Sea Reservoirs

Summary Field trials have demonstrated increased oil recovery by injection of colloidal dispersion gels (CDG). Characteristics of these trials include reservoirs characterized by high permeability heterogeneity and low injection water salinities. The enhanced oil recovery (EOR) has been attributed to improved waterflood sweep in the rather heterogeneous reservoirs where this method has been applied. This study presents an investigation of the applicability of CDG at higher salinity, and particularly sandstone North Sea oil reservoir applications. Earlier laboratory work and field trials involving CDG have involved relatively low reservoir temperatures and low injection water salinity (≈5000 μg/g). This study involves experiments at high temperature (85°C) and salinity (≈35 000 μg/g). When crosslinking is complete, the CDG solutions have slightly lower viscosities than the corresponding polymer solutions, and they also appear to be more stable at high temperatures. In preparation for a field pilot, several coreflood experiments have been conducted. Significant increase in oil recovery resulting from CDG injection has increased the interest for a field trial in a North Sea oil field. On average, 40% of the remaining oil after waterflooding was produced by CDG injection in linear core-floods, and a mechanism of microscopic diversion is proposed to explain these results. Our hypothesis is that CDG injection can contribute as an EOR method, giving both a microscopic diversion and a macroscopic sweep.

Full Scale VAPEX Process-Climate Change Advantage and Economic Consequences A

Abstract With the VAPEX process, combinations of vaporized solvents are injected into heavy oil and bitumen reservoirs for in situ recovery of the oil. The oil is diluted with the solvent, which reduces the viscosity so the oil drains by gravity to a horizontal production well. The VAPEX process has the potential to greatly reduce the greenhouse gas emissions for oil sands and heavy oil recovery since it is a non-thermal process that does not require the reservoir to be heated with, for example, steam. The Petroleum Recovery Institute (PRI) was the operator of a joint industry project of 16 participants with nine research performing organizations. During 1998, the project investigated the full project engineering and commercial scale economics for the VAPEX process. The supply cost economics for VAPEX oil production from the Athabasca oil sands, Cold Lake oil sands and Southeast Alberta heavy oil were determined. The work indicated that VAPEX has attractive economics and helped to define the critical field operations design issues that need to be addressed prior to proceeding with a substantial field pilot. The climate change advantages of the VAPEX process are described in the paper along with an overview of the integrated physical model, numerical simulation, facilities design, well specifications, production, transportation, and marketing work which led to calculation of the supply cost economics. Introduction The VAPEX (vapor extraction) process(1) is a non-thermal process that uses vaporized solvents that are injected into heavy oil or bitumen reservoirs. The solvent dissolves in the oil at the natural reservoir temperature, reducing the viscosity of the oil, which will then readily flow by gravity to a horizontal production well(2). The concept is described in several Canadian and USA patents(3, 4). As shown in Figure 1, twin horizontal wells are used for the recovery process. VAPEX gas is injected into the upper well where it dissolves in the oil, which then drains to the lower producer. The development of the VAPEX technology is shown pictorially in Figure 2. Since the initial patent in 1978, there has been basic and applied research and invention(2). In 1998, the PRI operated a project called "Development of Full Project Engineering and Economics for the VAPEX Process," with 16 participants and nine research performing organizations. The project continued in 1999 with Phase 2 for VAPEX operations design on "How to Operate VAPEX in the Field," which included conceptual design of two VAPEX pilot plants for an oil sands application and a heavy oil reservoir application with underlying water. The VAPEX process has several potential advantages and disadvantages for commercial scale economic oil production. The potential advantages are: no steam generation; no water processing/ recycle; lower fuel costs; greater energy efficiency; lower carbon dioxide emissions; may be advantageous in thin reservoirs or with bottom water, and potential in situ upgrading. The potential disadvantages are: solvent compression, solvent losses and potential sensitivity to reservoir heterogeneity. The advantages and disadvantages are reiterated in Tables 1 and 2.