Effect Of Oil Composition Research Articles

Effects of oil composition on interactions between paraffinic and asphaltenic components and the performance of paraffin inhibitors

The efficacy of three comb polymer paraffin inhibitors (PI) having distinct structural differences was assessed in oils of increasing complexity; dodecane, diesel and a light West Texas (WT) crude. Each oil contained added paraffin and was evaluated by means of cross-polarization microscopy (CPM) and rheological analysis. The effect of added asphaltenes on PI efficacy was also assessed. A PI possessing amide/imide functionality regarding the point of attachment of alkyl chains to the polymer backbone was not effective in the oils selected for study. Treated with each of two PIs having ester-functional attachment, the degree to which the wax appearance temperature (WAT) and the cooling-heating viscosity profiles of the resultant oils were reduced relative to their untreated counterparts correlates with the degree of crystal inter-connectivity observed in the CPM images. The PI having the lower chain density was more effective in WT crude, opposite a trend observed previously in dodecane-based oil, illustrating the impact of oil composition on the structure-activity relationships governing PI efficacy. Synergism between the PIs and added asphaltenes is evident in WT oil. A reasoning of our observations based on electrostatic shielding of carboxylic acid groups in the PIs is postulated. This study represents our efforts to better understand the effects of oil composition, particularly aromatics, resins and asphaltenes on the structure-activity relationships governing the ability of comb polymer PIs to stabilize wax in different oils and identify correlations that guide both PI design and selection.

Effect of oil chemistry on the performance of low-salinity waterflooding in carbonates: An integrated experimental approach

Chemical enhanced oil recovery (cEOR) relies on the interactions between surface-active components (SACs) of the oil-in-place and injected chemicals to induce favorable physico-chemical changes. This study investigates the effect of oil chemistry on the performance of chemically-tuned waterflooding (CTWF) in carbonate rocks. Coreflood experiments were performed at 90°C using four model oils, each containing a single SAC (acetic acid, decanoic acid, stearic acid or quinoline) to evaluate the effect of oil composition on oil recovery. Complementary characterization techniques including thermal gravimetric analysis (TGA), attenuated total reflectance (ATR-FTIR) and zeta potential (ζ) were used to understand the underlying rock-oil-brine interactions that take place during CTWF, including SAC adsorption to the rock surface, strength of adsorption, partitioning into the brine phase, and electrostatic interactions, respectively. Sessile drop contact angle measurements were also performed to quantify the wetting behavior of the different SACs. Results of this study show that oil chemistry plays a significant role in triggering different oil-brine-rock interactions. Characterization of those interactions is crucial to explain the discrepancies in oil recovery observed in the CTWF literature. In this study, differences in the underlying oil-brine-rock interactions translated into significant variation in oil recovery ranging between 8.9 and 43.9 % after one pore volume injected (PVI). ATR-FTIR results showed that in-situ soap generation was detected for oils with longer chain carboxylic acids, whereas no soaps were observed for oils that have acetic acid or quinoline. Combined with sessile-drop contact angle measurements, a relationship is observed between SAC partitioning into the brine phase and water-wetting behavior. Additionally, TGA measurements suggested that long chain carboxylic acids chemisorb to the rock surface, making wettability alteration to a less oil-wetting state during CTWF more challenging, whereas intermediate chain carboxylic acids only physisorb leading to a more pronounced wettability alteration to a less oil-wetting state, ultimately yielding the highest recovery of ∼49.9 %. Finally, TAN was found to be an insufficient oil descriptor, where oils with the same TAN yielded different CTWF effects. Hence, a more robust oil analysis is crucial for more accurate prediction and modeling of CTWF behavior.

Investigation of crude oil properties impact on wettability alteration during low salinity water flooding using an improved geochemical model

In low-salinity water flooding (LSWF), modifying the injected brine composition leads to greater oil recovery from carbonate reservoirs. The processes that control improved recovery during LSWF are not totally clear, which could lead to ambiguities in finding optimum brine composition regarding wettability alteration (WA) toward water wetness. One of the methods to determine WA is bound product sum (BPS) calculation using geochemical tools. In the case of wettability improvement, the BPS value of a crude oil-brine-rock (COBR) system should be at its minimum value. In this study, an improved geochemical model is developed, which includes the effects of oil composition (i.e., acid number, base number, and weight percent of nonhydrocarbon components) and physical properties of oil (i.e., density, viscosity, and solution gas-oil ratio) on COBR interactions. The proposed method generates BPS as a function of temperature, pressure, oil and brine composition, and pH for carbonate rocks. The model applicability was validated using several experimental data sets available in the literature. The results of the improved BPS model were in line with the results of contact angle and zeta potential measurements as the major indices of rock wettability. BPS calculations using the available geochemical tools sometimes failed to predict the correct WA trend since they overlooked the impact of oil properties on COBR interactions. The model predictability was also compared with the results of an available geochemical tool, PHREEQC, and the results demonstrate just how important the effect of oil properties and composition inclusion on wettability determination is. The improved BPS approach could be successfully utilized as an optimization tool to optimize the water composition during LSWF for a given COBR system.

Role of Asphaltene in Stability of Water-in-Oil Model Emulsions: The Effects of Oil Composition and Size of the Aggregates and Droplets

Water-in-oil (W/O) emulsions are the most common type of emulsions handled in petroleum processes. It is thought that the field emulsions are primarily stabilized by asphaltene–resin micelles, and ...

Adsorption of Crude Oil Components on Mineral Surfaces Followed by Quartz Crystal Microbalance and Contact Angle Measurements: The Effect of Oil Composition, Simulated Weathering and Dispersants

Improved knowledge of interactions between crude oil and solid surfaces is of great importance for understanding oil spill responses as well as oil spill behavior on land and in the near-shore environment. Here, the goal was to study how crude oils with various physicochemical properties interacted with model shoreline surfaces. In addition, the influence of simulated weathering and addition of dispersants was investigated for selected crude oils. A quartz crystal microbalance was used to follow the adsorption from 13 different crude oils on silica, aluminosilicate, and calcium carbonate surfaces, whereas the corresponding wettability alterations were followed by contact angle measurements. The polar crude oil components adsorbed in considerably higher amounts on the calcium carbonate surfaces than on the silica and aluminosilicate surfaces. The simulated weathering of oils resulted in increased adsorption onto both the silica and aluminosilicate surfaces, whereas it had a little effect on the calcium carbonate surface. The presence of dispersants generally reduced the amounts adsorbed on the surfaces. In the presence of seawater, the crude oil with a higher total acid number interacted strongest with the calcium carbonate surface.

Experimental Investigation of the Effect of Oil on Steady-State Foam Flow in Porous Media

Summary Foam flow in porous media without oil shows two regimes depending on foam quality (gas fractional flow). Complexity and limited data on foam/oil interactions in porous media greatly restrict understanding of foam in contact with oil. Distinguishing which regimes are affected by oil is key to modeling the effect of oil on foam. We report steady-state corefloods to investigate the effect of oil on foam through its effect on the two flow regimes. We fit the parameters of a widely used local-equilibrium (LE) foam model to data for concurrent foam/oil flow. This research provides a practical approach and initial data for simulating foam enhanced oil recovery (EOR) in the presence of oil. To ensure steady state, oil is coinjected with foam at a fixed ratio of oil (Uo) to water (Uw) superficial velocities in a Bentheimer Sandstone core. Model oils used here consist of a composition of hexadecane, which is benign to foam stability, and oleic acid (OA), which can destroy foam. Varying the concentration of OA in the model oil allows one to examine the effect of oil composition on steady-state foam flow. Experimental results show that oil affects both high- and low-quality regimes, with the high-quality regime being more sensitive to oil. In particular, oil increases the limiting water saturation (Sw*) in the high-quality regime and also reduces gas-mobility reduction in the low-quality regime. Unevenly spaced ▿p contours in the high-quality regime suggest either strongly shear-thinning behavior or an increasingly destabilizing effect of oil. In some cases, the pressure gradient (▿p) in the low-quality regime decreases with increasing Uw at fixed gas superficial velocity (Ug), either with or without oil. This might reflect either an effect of oil, if oil is present, or easier flow of bubbles under wetter conditions. Increasing the OA concentration extends the high-quality regime to lower foam qualities, indicating more difficulty in stabilizing foam. Thus, oil composition plays as significant a role as oil saturation (So). A model fit assuming a fixed Sw* and including shear thinning in the low-quality regime does not represent the two regimes when the oil effect is strong enough. In such cases, fitting Sw* to each ▿p contour and excluding shear thinning in the low-quality regime yield a better match to these data. The dependency of Sw* on So is not yet clear because of the absence of oil-saturation data in this study. Furthermore, none of the current foam-simulation models captures the upward-tilting ▿p contours in the low-quality regime.

Main factors influencing the formation of thermogenic solid bitumen

Highly mature solid bitumen, a residue of oil cracking, is widespread in the lower Paleozoic paleo-oil reservoirs of southern China. Solid bitumen is not a simple, pure component, but rather a compositionally and structurally variable mixture of materials. This study investigated the formation of thermogenic solid bitumen and the effects of oil composition and reservoir environment. A series of seven gold-tube pyrolysis experiments were conducted: three used the main fraction groups (i.e., saturated, aromatic, and resin + asphaltene fractions) of crude oil to evaluate the effect of oil composition on the formation of solid bitumen during cracking; the other four tested the effects of water and pressure in reservoirs by simulating the cracking of crude oil under different reservoir conditions. Quantitative analyses of pyrolytic products (including methane, C2–C5 gaseous hydrocarbons, C6–C13 light hydrocarbons, C13+ heavy hydrocarbons, and solid bitumen) indicated that thermogenic solid bitumen formed at different stages of oil cracking, and its formation was clearly affected by oil composition. In contrast, water and pressure in the reservoir had little effect on the formation of solid bitumen.

Understanding Model Crude Oil Component Interactions on Kaolinite Silicate and Aluminol Surfaces: Toward Improved Understanding of Shale Oil Recovery

Shale oil is currently of interest for unconventional resource exploration and development. Understanding the mechanism of interaction between the complex mixture of organic compounds in shale oil and minerals making up the reservoir rock–oil interface will assist recovery. In this study, molecular dynamics simulation is used to study the adsorption characteristics of a model oil mixture within nanoscale intraparticle pores of kaolinite minerals, which form pore-filling structures in shale rock. To better understand the effects of oil composition, temperature, and pressure on the adsorption properties of the model oil mixture, a range of temperatures (298, 323, 348, and 373 K) and pressures (1, 50, 100, and 200 bar) representing up to reservoir conditions were used. This study shows that adsorption and arrangement of oil molecules is dependent on the surface of kaolinite and the distance away from it. The simulations show polar compounds are likely to be adsorbed on aluminol kaolinite basal surfaces, whil...

Experimental analysis of calcium carbonate scale formation and inhibition in waterflooding of carbonate reservoirs

Deposition of inorganic salts such as calcium carbonate (CaCO3) can cause formation damage and production equipment failure during the development of a reservoir. In case of waterflooding, complex geochemical processes between the injection water, formation water and rock occur and the concentration of ions increases. Major contribution of scale control concentrates on understating the conditions scale formation and its inhibition.In this paper, we analyze experimentally the effect of oil composition and flow conditions on CaCO3 scale formation. We measured the induction period of CaCO3 crystallization in a stirred vessel with different Reynold numbers and the interfacial tension at the boundary between the aqueous scale inhibitor and oil at different percentages of organic components. In addition, we determined the performance of CaCO3 scale inhibition under different static and dynamic conditions in some Iranian carbonate core samples.The experimental results showed that if the interfacial tension was reduced by increasing the concentration of organic components to 1.5%, the CaCO3 precipitation decreases more than 30%. In addition, increasing the flow velocity (Reynolds number) had a great influence on the increase in the induction period of CaCO3 crystallization. However, the induction period was insignificantly changed at higher values.Using a recently developed scale inhibitor, we kept the CaCO3 formation at a constant concentration of 30mg/L. The efficiency of the inhibitor was insignificantly reduced if the temperature is increased up to 120°C. Core flooding experiments show that formation damage due to CaCO3 precipitation depends on the injection rate of the solution. In addition, the formation damage was mitigated to the 93% of initial permeability of the core samples. The results of this work improve our understanding from CaCO3 formation and can be used to predict and prevent it during waterflooding process in carbonate reservoirs.

Atomistic Molecular Dynamics Simulations of Crude Oil/Brine Displacement in Calcite Mesopores

Unconventional reservoirs such as hydrocarbon-bearing shale formations and ultratight carbonates generate a large fraction of oil and gas production in North America. The characteristic feature of these reservoirs is their nanoscale porosity that provides significant surface areas between the pore walls and the occupying fluids. To better assess hydrocarbon recovery from these formations, it is crucial to develop an improved insight into the effects of wall-fluid interactions on the interfacial phenomena in these nanoscale confinements. One of the important properties that controls the displacement of fluids inside the pores is the threshold capillary pressure. In this study, we present the results of an integrated series of large-scale molecular dynamics (MD) simulations performed to investigate the effects of wall-fluid interactions on the threshold capillary pressures of oil-water/brine displacements in a calcite nanopore with a square cross section. Fully atomistic models are utilized to represent crude oil, brine, and calcite in order to accommodate electrostatic interactions and H-bonding between the polar molecules and the calcite surface. To this end, we create mixtures of various polar and nonpolar organic molecules to better represent the crude oil. The interfacial tension between oil and water/brine and their contact angle on calcite surface are simulated. We study the effects of oil composition, water salinity, and temperature and pressure conditions on these properties. The threshold capillary pressure values are also obtained from the MD simulations for the calcite nanopore. We then compare the MD results against those generated using the Mayer-Stowe-Princen (MSP) method and explain the differences.

Visualization of CO2 EOR by Molecular Diffusion in Fractured Chalk

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170920, “Visualization of CO2 EOR by Diffusion in Fractured Chalk,” by øyvind Eide, SPE, Martin A. Fernø, SPE, and Arne Graue, SPE, University of Bergen, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed. This work demonstrates that molecular diffusion may be a viable oil-recovery mechanism in fractured reservoirs during injection of carbon dioxide (CO2) for enhanced oil recovery (EOR). The oil-production rate from diffusion alone, however, depends heavily on the distribution of CO2 within the fracture network and fracture spacing. A numerical sensitivity analysis, using a validated numerical model that reproduced the experiments, showed that the rate of oil production during CO2 injection declined exponentially with increasing diffusion lengths from the CO2-filled fracture and the oil-filled matrix. Introduction Compared with other EOR methods based on gas injection, CO2 injection has many beneficial properties, among them that CO2 lowers the gas/oil interfacial tension and reduces oil viscosity and density, resulting in increased oil mobility and oil swelling. The main drawback with injecting gas is the high mobility, a factor especially true in fractured reservoirs. The success of a potential CO2 EOR project increases when key driving forces for oil displacement during a CO2 injection are identified. In a highly fractured reservoir, molecular diffusion could be an important driving mechanism; however, it would require high fracture density. Molecular diffusion is the mixing of fluids caused by random motion of molecules, and its calculation is described in detail in the complete paper. Diffusion is often neglected as a production mechanism during modeling of CO2 injection in oil reservoirs because it is computationally expensive to handle and is assumed to be of minor importance. While this might be true for most conventional reservoirs, it is not true for heavily fractured reservoirs and in laboratory experiments, where the diffusion distances are much smaller. Experimental Setup Fluids. A one-component pure mineral oil (decane) was used as the oleic phase in the experiment to achieve first-contact- miscible conditions with CO2 at pressures below 10 MPa to eliminate the effect of oil composition and to promote repeatability between tests. Core Material. Outcrop Rørdal chalk from Denmark was used in this study as an analog for North Sea chalk reservoirs. It has a composition of mainly calcite (99%) and some quartz (1%) and consists mainly of coccolith deposits. The Rørdal chalk is a homogeneous chalk type with similar porosity and permeability values between sister core plugs. Core Preparation. A smooth-walled, artificial, longitudinal fracture was cut in Core Plug C1 using a band saw. A constant fracture aperture of 1 mm was maintained by use of a polyoxymethylene (POM) spacer. The spacer consisted of three large void compartments separated by support columns, and flow between each void was through grooves to allow for fluid transport. The permeability of the fracture was several orders of magnitude higher than that of the matrix. Experimental Setup. The scanner was a fourth-generation medical computed-tomography (CT) scanner with a scanning time of 3 minutes and a pixel resolution of 160×160 Μm and a slice thickness of 500 Μm. The core was first scanned to localize its position and to ensure a vertical fracture plane. The core was then vacuum evacuated before a 100% dry image was measured. A 100%- CO2 image was obtained after the core was fully saturated with CO2. The system was then depressurized, vacuum evacuated, and fully saturated with oil before the oil calibration scan was obtained. All 100%-saturation scans were performed at experimental pressure and temperature (10.7 MPa and 42°C, respectively). The mineral oil decane was used in all tests. The test conditions used ensured supercritical CO2 conditions and first-contact miscibility between CO2 and decane. The confinement pressure was kept 1 MPa above the line pressure.

Behavior of Re and Os during contact between an aqueous solution and oil: Consequences for the application of the Re–Os geochronometer to petroleum

Several recent studies have raised the exciting possibility that oils can be dated using the Re–Os radioisotope system. However the exact nature of the events dated by this technique often remains unclear. Geochronologic interpretation of Re–Os data for oils is hampered by our limited knowledge of how these metals behave in petroleum systems. In particular, it is difficult to understand how isotopic homogenization, an essential prerequisite for the development of an isochronal relationship, can be achieved at the scale of a petroleum basin. The mechanisms capable of fractionating the Re/Os ratio in a suite of oils are also poorly understood. For this reason, we have performed an experimental study aimed at investigating the behavior of Re and Os during a particularly widespread phenomenon in petroleum systems, the interaction of formation waters with oils during migration. Contact experiments between natural oils and aqueous solutions enriched in Re and/or Os were carried out for varying lengths of time (6h to 5months), at different temperatures (25–150°C), over a wide range of metal concentrations in the enriched solution (0.001–100μg/g for Re; 1 and 10ng/g for Os). In addition, the effect of oil composition on Re–Os exchange at the water–oil interface was examined by testing two oils with very different properties.All of our results demonstrate that Re and Os are transferred massively and very rapidly from the aqueous solution to the organic phase. This is true regardless of temperature or oil composition. It is also true for a very wide range of metal concentrations in the aqueous solution, up to an apparent saturation level that exceeds natural concentrations in oils by several orders of magnitude. Given the efficiency of Re and Os transfer from water to oil demonstrated here, and assuming that our findings are applicable to natural conditions, water/oil ratios of only about 250 would be needed to explain the Re and Os contents of most oils, based on the measured concentrations of Re and Os in groundwaters. Thus transfer of Re and Os from formation waters could plausibly provide a source for these metals in oils. Waters from a given basin may have roughly homogeneous Os isotopic compositions, approximating the average value of the source rocks. On the other hand, variable Re/Os ratios might be expected to develop, as a result of interaction with various phases (e.g. Fe–Mn oxides or authigenic pyrite) encountered by the water as it flows through the reservoir. If homogeneous 187Os/188Os ratios coupled with variable Re/Os ratios are transferred to the oils with which the waters come in contact, the isotopic geochronometer could be reset.

Effect of oil composition on fluid substitution in heavy oil reservoirs

ABSTRACTUnlike light oils, heavy oils do not have a well‐established scheme for modelling elastic moduli from dynamic reservoir properties. One of the main challenges in the fluid substitution of heavy oils is their viscoelastic nature, which is controlled by temperature, pressure, and fluid composition. Here, we develop a framework for fluid substitution modelling that is reliable yet practical for a wide range of cold and thermal recovery scenarios in producing heavy oils and that takes into account the reservoir fluid composition, grounded on the effective‐medium theories for estimating elastic moduli of an oil–rock system. We investigate the effect of fluid composition variations on oil–rock elastic moduli with temperature changes. The fluid compositional behaviour is determined by flash calculations. Elastic moduli are then determined using the double‐porosity coherent potential approximation method and the calculated viscosity based on the fluid composition. An increase in temperature imposes two opposing mechanisms on the viscosity behaviour of a heavy‐oil sample: gas liberation, which tends to increase the viscosity, and melting, which decreases the viscosity. We demonstrate that melting dominates gas liberation, and as a result, the viscosity and, consequently, the shear modulus of the heavy oils always decrease with increasing temperature. Furthermore, it turns out that one can disregard the effects of gas in the solution when modelling the elastic moduli of heavy oils. Here, we compare oil–rock elastic moduli when the rock is saturated with fluids that have different viscosity levels. The objective is to characterize a unique relation between the temperature, the frequency, and the elastic moduli of an oil–rock system. We have proposed an approach that takes advantage of this relation to find the temperature and, consequently, the viscosity in different regions of the reservoir.

Formation and stabilization of nanoemulsion-based vitamin E delivery systems using natural surfactants: Quillaja saponin and lecithin

Natural small molecule surfactants (lecithin and quillaja saponin) were used to fabricate nanoemulsion-based delivery systems from vitamin E acetate using high pressure homogenization. The effect of oil composition (0–100% vitamin E acetate), surfactant type, and surfactant concentration (0.0005–5%) on the mean particle diameter (d32) and vitamin loading capacity was examined. The mean particle diameter had a minimum value at an intermediate vitamin E-to-orange oil ratio in the oil phase: d32=0.13μm for lecithin and 0.12μm for quillaja saponin at 50% vitamin E. The mean particle diameter decreased with increasing surfactant concentration for both surfactants, with lower levels of quillaja saponin being required to form small droplets. The effect of pH, ionic strength, and temperature on the physical stability of the nanoemulsions was also investigated. Both surfactants formed unstable nanoemulsions at pH 2, which was attributed to loss of electrostatic repulsion due to a reduction in droplet charge. Emulsion instability was also observed at >100mM NaCl for lecithin and ⩾400mM NaCl for quillaja saponin, which was attributed to electrostatic screening. Both systems were stable at temperatures from 30 to 90°C (pH 7), i.e., no particle growth or creaming was observed. These results provide useful information about the emulsifying and stabilizing capacities of natural surfactants intended for use in the food and other industries.

Low-Temperature Oxidation of Oil Components in an Air Injection Process for Improved Oil Recovery

Air injection is an effective technique for improved oil recovery in light oil reservoirs. It is speculated that the main mechanism of the process is via spontaneous low-temperature oxidation (LTO) to consume oxygen and generate “flue gas” that displaces oil out of the reservoir. In this study, laboratory experiments have been conducted to study the effects of oil composition and main reservoir parameters on the kinetics of LTO, in a range of reservoir temperatures from 70 to 150 °C. Saturates, aromatics, resins, and asphaltenes (SARA) analysis and experiments using pure oil components were preformed to study the oxidation activity of different oil compounds and components. Reaction rates of typical light and heavy oil samples were also measured for comparison. Effects of temperature, pressure, water saturation, sand type, and residence time on reaction rates and products were investigated under static and dynamic conditions. The results indicate that different oil components exhibit different reaction ac...

Immunomodulatory and physical effects of oil composition in vaccine adjuvant emulsions

Squalene-based oil-in-water emulsions have been used for years in some seasonal and pandemic influenza vaccines. However, concerns have been expressed regarding squalene source and potential biological activities. Little information is available regarding the immunomodulatory activity of squalene in comparison with other metabolizable oils in the context of oil-in-water emulsions formulated with vaccines. The present work describes the manufacture and physical characterization of emulsions composed of different classes of oils, including squalene, long chain triglycerides, a medium chain triglyceride, and a perfluorocarbon, all emulsified with egg phosphatidylcholine. Some differences were apparent among the non-squalene oils in terms of emulsion stability, including higher size polydispersity in the perfluorocarbon emulsion, more rapid visual instability at 60°C for the long-chain triglyceride and perfluorocarbon emulsions, and an increased creaming rate in the medium-chain triglyceride emulsion at 60°C as detected by laser scattering optical profiling. The biological activity of each of these emulsions was compared when formulated with either a recombinant malaria antigen or a split-virus inactivated influenza vaccine. Overall, vaccines containing the squalene emulsion elicited higher antibody titers and more abundant long-lived plasma cells than vaccines containing emulsions based on other oils. Since squalene-based emulsions show higher adjuvant potency compared to the other oils tested, non-squalene oils may be more suitable as carriers of amphiphilic or hydrophobic immunostimulatory molecules (such as TLR agonists) rather than as stand-alone adjuvants.

Effect of Oil Composition on Chemical Dispersion of Crude Oil

Effects of oil composition on dispersion effectiveness (defined as the mass fraction of oil entrained as droplets in the water column) and droplet-size distribution were investigated using baffled-flask mixing systems. The composition of oil samples used in dispersion experiments was systematically manipulated by varying the relative concentrations of the saturates, aromatics, resins, and asphaltenes (SARA) fractions. Forward stepwise linear regression was used with a generalized linear model that included main effects and two-factor interactions to evaluate the effects of oil composition on chemical dispersion. Limited sensitivity analysis was used to determine whether the significant effects were strongly dependent on the specific combination of responses observed in these experiments or insensitive to small changes within the range of variation that was observed. The concentration of the aromatics fraction and the saturates–resins interaction exerted statistically significant, positive effects on dispersion effectiveness (p<0.05). Regardless of composition, the droplet-size distributions observed in these experiments were multimodal consisting of small- (<7 μm), medium- (7–20 μm), and large-sized (>20 μm) droplets. Higher concentrations of the saturates fraction favored the entrainment of floating oil as small and medium-sized droplets, whereas the aromatics–asphaltenes interaction reduced the amount of oil present as small droplets. Aromatics–asphaltenes interaction increased the overall diameter of mean volume (DMV) of the dispersed oil droplets, and the saturates–asphaltenes interaction reduced it.

An Investigation of the Effect of Oil Composition on Heavy-Oil Solution Gas Drive

Summary This study probes experimentally the mechanisms of heavy-oil solution gas drive through a series of depletion experiments employing two heavy crude oils and two viscous mineral oils. Mineral oils were chosen with viscosity similar to crude oil at reservoir temperature. A specially designed aluminum coreholder allows visualization of gas phase evolution during depletion using X-ray computed tomography (CT). In addition, a visualization cell was installed at the outlet of the sandpack to monitor the flowing-gas-bubble behavior vs. pressure. Bubble behavior observed at the outlet corroborates CT measurements of in-situ gas saturation vs. pressure. Both depletion rate and oil composition affect the size of mobile bubbles. At a high depletion rate (0.035 PV/hr), a foam-like flow of relatively small pore-sized bubbles dominates the gas and oil production of both crude oils. Conversely, at a low depletion rate (0.0030 PV/hr), foam-like flow is not observed in the less viscous crude oil; however, foam-like flow behavior is still found for the more viscous crude oil. No foam-like flow is observed for the mineral oils. In-situ imaging shows that the gas saturation distribution along the sandpack is not uniform. As the pattern of produced gas switches from dispersed bubbles to free gas flow, the distribution of gas saturation becomes even more heterogeneous. This indicates that a combination of pore restrictions and gravity forces significantly affects free gas flow. Additionally, results show that solution-gas drive is effective even at reservoir temperatures as great as 80°C. Oil recovery ranges from 12 to 30% OOIP; the higher the depletion rate, the greater the recovery rate.

Factors Affecting Chemical Remediation of Oil Contaminated Water‐Wetted Soil

AbstractThe removal of hydrocarbons from contaminated soil is an essential practice because of environmental concerns, and in order to avoid surface and groundwater contamination. There are different methods applied to remove the hydrocarbons from the soil environment. However, the efficiency of soil remediation depends on several factors, such as the penetration depth of the oil into the soil, the type of oil and polluted soil and the age and degree of contamination. Chemical extraction is one of the approaches employed in handling contaminated sites. Many operations in the petroleum exploration, production and transportation have the potential to affect the environment in different degrees. Leakages from pipelines and stranded oil spills are the major sources of oil‐contamination. If hydrocarbon contamination occurs in the soil, the affected portion of soil must be treated to prevent subsequent pollution of groundwater. In this study, a laboratory investigation of factors affecting the chemical extraction using different solvents was conducted to remove the hydrocarbon from artificially contaminated soil samples in presence of water. Moreover, two different types of crude oil were used to study the effect of oil composition on the removal process. The results have identified large variation in the removal efficiency of the applied solvents, depending mainly on the solvent and the type of oil. The main factors affecting the removal process are presented and investigated. In addition, these results were compared with those of dry soil samples.

Investigation of electrostatic charging mechanisms in oil lubricated tribo-contacts

Fundamental studies using a spinning disc tribocharging rig have shown that disc surface roughness, oil temperature and oil composition have an effect on the charging ability of lubricating oils. Further investigations into the effect of oil composition on the charging nature have employed the oil droplet rig to investigate a range of base and formulated oils. Experimental results indicated that charging in base oils is controlled by levels of impurities, such as sulphur, and aromatic content. For formulated oils it has been determined that the additives are the major contributor to the charging nature and any effect that impurities and aromatics have is negligible. Studies into the sensitivity of the electrostatic sensor system to surface charge has shown that surface transformations that occur during scuffing in tribocontacts can lead to contact potential differences detectable by this system.