Investigation of the Hydrate Plugging and Non-Plugging Properties of Oils

Three laboratories (Norwegian Institute of Science and Technology [NTNU], Institut Français du Pétrole [IFP], and the Colorado School of Mines [CSM]) determined hydrate plug formation characteristics in three oils, each in three conditions: (1) in their natural state, (2) with asphaltenes removed, and (3) with naturally occurring acids removed from the oil. The objective was to determine the major variables that affect hydrate plugging tendencies in oil-dominated systems, to enable the flow assurance engineer to qualitatively assess the tendency of an oil to plug with hydrates. In the past, it was indicated that chemical effects, for example, water-in-oil/hydrate-in-oil (emulsion/dispersion) stability, prevented hydrate plugs. For example, deasphalted oils provided low emulsion/dispersion stability and thus hydrate particles aggregated. In contrast pH 14-extracted oils were reported to remove stabilizing naphthenic acids, causing asphaltene precipitation on water/hydrate droplets, stabilizing the emulsion/dispersion to prevent aggregation and pluggage. This work suggests that in addition to chemistry, shear can enable plug-free operation in the hydrate region. High shear can prevent hydrate particle aggregation, while low shear encourages particle aggregation and plugging. As a result, flow assurance engineers may be able to forecast hydrate plug liability of an oil by a combination of chemistry and flow variables, such as: a) measurements of live oil emulsion stability, b) predictions of flow line shear, and c) knowledge of water cut. Plug formation qualitative trends are provided for the above three variables. Implications for flow assurance are given.     

Some aspects of hydrate formation and wetting

Experimental observations of gas hydrate formation have shown that, in the initial nucleation and crystallization process, water-oil emulsions may be generated, destabilized or even inverted. These phenomena are consistent with the effects of particles on emulsions. In this work we relate experimental observations of hydrate formation to the phenomenon of wettability. It is shown that details of hydrate wetting are important for both the morphology and the kinetics of the formed hydrates. For the cases of hydrate lenses and spheres, it is shown that the various wetting states can be illustrated and analyzed by using wetting diagrams. Metastability is a function of the surface energies of the hydrate formation, i.e., the wetting state, and it is shown that in some cases metastability vanishes, and thus hydrates nucleates instantly at all positive driving forces. The magnitude of buoyancy and turbulence forces acting on a hydrate sphere are compared to the capillary force and it is concluded that capillary energy dominates when the hydrate spheres is less than 1 mm.     

Effect of Inorganic Solids,Wax to Asphaltene Ratio,and Water Cut on the Stability of Water-in-Crude Oil Emulsions

The formation of stable water-in-crude oil emulsions during petroleum production and refinery may create sever and costly separation problems. It is very important to understand the mechanism and factors contributing to the formation and stabilization of such emulsions for both great economic and environmental development. This article investigates some of the factors controlling the stability of water-in-crude oil emulsions formed in Burgan oil field in Kuwait. Water-in-crude oil emulsion samples collected from Burgan oil filed have been used to separate asphaltenes, resins, waxes, and crude oil fractions. These fractions were used to prepare emulsion samples to study the effect of solid particles (Fe₃O₄) on the stability of emulsions samples. Results indicate that high solid content lead to higher degree of emulsion stability. Stability of emulsion samples under various waxes to asphaltenes (W/A) ratios have also been tested. These tests showed that at low W/A content, the emulsions were very stable. While at a wax to asphaltene ratio above 1 to 1, the addition of wax reduced emulsion stability. Stability of emulsion samples with varying amount of water cut has also been investigated. Results indicated that stability and hence viscosity of emulsion increases as a function of increasing the water cut until it reaches the inversion point where a sharp decline in viscosity takes place. This inversion point was found to be approximately at 50% water cut for the crude oils considered in this study.     

固体粒子稳定的乳状液研究进展

综述了固体粒子对乳状液稳定性影响的有关研究进展。微细不溶的固体粒子构成重要的一类乳化剂,被水相和油相部分润湿的固体粒子能够有效地稳定乳状液。固体粒子稳定乳状液的效果取决于以下因素:粒子大小、粒子间相互作用和粒子的润湿性质。固体粒子存在的油-水界面表现出粘弹行为,这种粘弹界面膜可大大地提高空间位阻,减缓乳状液液珠间液膜变薄的速率,从而提高乳状液地稳定性。原油中的粘土、胶质、沥青质和石蜡等胶体粒子被证明对乳状液的稳定性起很大的作用。     

A model for estimating flow assurance of hydrate slurry in pipelines

The problem of hydrate blockage of pipelines in offshore production is becoming ever-increasing severe because oil fields in ever-increasing unusual environments have been brought in production.HCFC-141b and THF were selected as the substitutes to study the flow assurance of the hydrates in pipelines.There are critical hydrate volume concentrations for these two slurries.Hydrate slurries behave like Bingham fluids and have high agglomerating tendency when the hydrate volume concentrations are larger than the critical ones.Based on theological behaviors of these two hydrates,a non-dimensional parameter is proposed through studying the driving forces of agglomeration among hydrate particles,which shows the agglomerating probability of hydrate particles in pipeline and can be used to judge the safety of the pipeline.Moreover,a safe model to judge the safely flow hydrate slurries was presented and verified with the experimental data,which demonstrates that the model is effective to judge whether the pipeline can be run safely or not.     

Detecting gas hydrate behavior in crude oil using NMR

Because of the associated experimental difficulties, natural gas hydrate behavior in black oil is poorly understood despite its grave importance in deep-water flow assurance. Since the hydrate cannot be visually observed in black oil, traditional methods often rely on gas pressure changes to monitor hydrate formation and dissociation. Because gases have to diffuse through the liquid phase for hydrate behavior to create pressure responses, the complication of gas mass transfer is involved and hydrate behavior is only indirectly observed. This pressure monitoring technique encounters difficulties when the oil phase is too viscous, the amount of water is too small, or the gas phase is absent. In this work we employ proton nuclear magnetic resonance (NMR) spectroscopy to observe directly the liquid-to-solid conversion of the water component in black oil emulsions. The technique relies on two facts. The first, well-known, is that water becomes essentially invisible to liquid state NMR as it becomes immobile, as in hydrate or ice formation. The second, our recent finding, is that in high magnetic fields of sufficient homogeneity, it is possible to distinguish water from black oil spectrally by their chemical shifts. By following changes in the area of the water peak, the process of hydrate conversion can be measured, and, at lower temperatures, the formation of ice. Taking only seconds to accomplish, this measurement is nearly direct in contrast to conventional techniques that measure the pressure changes of the whole system and assume these changes represent formation or dissociation of hydrates - rather than simply changes in solubility. This new technique clearly can provide accurate hydrate thermodynamic data in black oils. Because the technique measures the total mobile water with rapidity, extensions should prove valuable in studying the dynamics of phase transitions in emulsions.     

Inversion of silica-stabilized emulsions induced by particle concentration

Emulsions of equal volumes of a cyclic silicone oil and water stabilized by fumed silica nanoparticles alone can be inverted from oil-in-water (o/w) to water-in-oil (w/o) by simply increasing the concentration of particles. The phenomenon is found to be crucially dependent both on the inherent hydrophobicity of the particles and on their initial location. Inversion only occurs in systems with particles of intermediate hydrophobicity when dispersed in oil; emulsions prepared from the same particles but initially dispersed in water remain o/w at all particle concentrations. The stability and drop size distributions in the different emulsions are compared. Various hypotheses are put forward and argued to explain this novel inversion route including adsorption of oil onto particle surfaces, hysteresis of contact angle affecting particle wettability in situ, and the structure of particle dispersions in oil or water prior to emulsification inferred from rheology and light scattering measurements. We propose that the tendency for particles to behave more hydrophobically at higher concentrations in oil is due to the reduction in the effective silanol content at their surfaces as a result of gel formation via silanol-silanol hydrogen bonds. In water, solvation of particle surfaces prevents this from occurring and particles behave as hydrophilic ones at all concentrations. A concentration-induced change in particle wettability is thus advanced.     

Fabrication of macroporous foam and microspheres of polystyrene by Pickering emulsion polymerization

Poly(styrene-co-methacrylic acid) (PS-co-MAA) particles were synthesized via surfactant-free emulsion polymerization and then used as particulate emulsifiers for preparation of Pickering emulsions. Our results showed that adjusting the solution pH can tune the wettability of PS-co-MAA particles to stabilize either water-in-oil (W/O) or oil-in-water (O/W) Pickering emulsions. Stable W/O emulsions were obtained with PS-co-MAA particles at low pH values due to their better affinity to the dispersed oil phase. In contrast, increasing the pH value significantly changed the stabilizing behavior of the PS-co-MAA particles, leading to the phase inversion and formation of stable O/W emulsions. We found that the oil/water ratio had a significant influence on pH value of the phase inversion. It decreased with decreasing the oil/water ratio, and no phase inversion occurred when the styrene volume fraction reduced to 10 %. Additionally, macroporous polystyrene (PS) foam and PS microspheres were obtained via polymerization of Pickering high internal phase emulsion (Pickering HIPE) and O/W Pickering emulsion, respectively.     

FLOW PROPERTIES OF WEATHERED CRUDE OILS AND THEIR EMULSIONS

The present paper proposes the emulsification of weathered crude oils in water as a competitive and cost effective method for reducing their viscosities. Weathered crude oil samples were collected from major Kuwaiti oil lakes. Emulsion preparation involved using, either a nonionic surfactant or alkali, as well as both alkali and fatty acid. The obtained emulsions were characterized by measuring the droplet size distribution of the dispersed phase using optical microscopy. Emulsion stability was also examined in terms of the system breakdown. The rheological properties were measured using a concentric cylinder rotary rheometer. The emulsion rheological behavior has been studied as a function of composition, temperature, and shear rate. A constitutive model was developed to characterize the pseudoplastic behavior of the crude oil and the emulsion systems. The model fitted well the experimental results with a correlation coefficient higher than 95%. Associated with the pseudoplastic behavior, viscoelastic behavior has been observed with emulsions and some oils at high shear rates.

The results of this investigation indicated that the examined weathered crude oils can be transported through pipelines as emulsions of up to 80 vol.% oil concentrations. The proposed method of treatment with NaOH and oleic acid offers several advantages over the surfactant treatment. It exhibited comparable rheological behavior at lower cost and less mixing energy. It also provided higher emulsion stability, which favors oil transportation for longer distances.     

Specific features of the growth,composition, and content of natural gas hydrates synthesized in inverted oil emulsions

A study of specific features of the growth, composition, and content of natural gas hydrates formed in a water-in-oil emulsion demonstrated that the process in which hydrates are formed in a water-oil emulsion occurs in stages and depends on the saturation of hydrate growth zones with the hydrate-forming gas via diffusion of natural-gas components across the oil phase. Hydrates enriched in methane are formed in water-oil emulsions, compared with the hydrates grown from distilled water, which is accounted for by the difference in solubility between natural-gas components in oil and water, and also by the presence of a surfactant layer on the surface of emulsified water drops. With increasing fraction of water in an emulsion, the content of hydrates decreases, and the mass of a hydrate being formed is independent of the composition of the water-oil emulsion.     

Application potential of in situ emulsion flooding in the high-temperature and high-salinity reservoir

In this research, an emulsifier formulation named SC-18 for W/O system was screened out and evaluated for feasible application of in-situ emulsion flooding in high-temperature and high-salinity reservoir. Results showed that SC-18 could reduce interfacial tension to 10–2 order of magnitude and change rock wettability from oil-wet to water-wet, which was beneficial to decrease residual oil saturation and improve displacement efficiency. Meanwhile, rheological testing showed that emulsion produced by SC-18 exhibited good temperature tolerance and mechanical stability, which favored mobility control and sweep efficiency enhancement under harsh conditions. In addition, good viscoelasticity of produced emulsions could also improve sweep efficiency by strengthening plugging and diverting effects of emulsion droplets, namely enhancing “Jiamin effects.” By means of natural core flooding and visualized plate model, it was proved that in-situ emulsion flooding with SC-18 could improve both displacement efficiency and sweep efficiency for high-temperature and high-salinity reservoir.     

Experimental Investigation of Rheological and Morphological Properties of Water in Crude Oil Emulsions Stabilized by a Lipophilic Surfactant

Rheological behavior of two crude oils and their surfactant-stabilized emulsions with initial droplet sizes ranging from 0.5 to 75 µm were investigated at various temperatures under steady and dynamic shear testing conditions. In order to evaluate the morphology and Stability of emulsions, microscopic analysis was carried out over three months and average diameter and size distribution of dispersed droplets were determined. The water content and surfactant concentration ranged from 10 to 60% vol/vol and 0.1 to 10% wt/vol, respectively. The results indicated that the rheological properties and the physical structure and stability of emulsions were significantly influenced by the water content and surfactant concentration. The crude oils behaved as Newtonian fluids over a wide range of shear rates, whereas the emulsions behaved as non-Newtonian fluids, indicating shear-thinning effects over the entire range of shear rates. The viscosity, storage modulus and degree of elasticity were found to be significantly increased with the increase in water content and surfactant concentration. The maximum viscosity was observed at the point close to the phase inversion point where the emulsion system changes from water-in-oil emulsion to oil-in-water emulsion. The results also indicated that the rheological properties of crude oils and their emulsions are significantly temperature-dependent.     

Influence of nanoscale particle roughness on the stability of pickering emulsions

The wetting behavior of solid surfaces can be altered dramatically by introducing surface roughness on the nanometer scale. Some of nature's most fascinating wetting phenomena are associated with surface roughness; they have inspired both fundamental research and the adoption of surface roughness as a design parameter for man-made functional coatings. So far the attention has focused primarily on macroscopic surfaces, but one should expect the wetting properties of colloidal particles to be strongly affected by roughness, too. Particle wettability, in turn, is a key parameter for the adsorption of particles at liquid interfaces and for the industrially important use of particles as emulsion stabilizers; yet, the consequence of particle roughness for emulsion stability remains poorly understood. In order to investigate the matter systematically, we have developed a surface treatment, applicable to micrometer-sized particles and macroscopic surfaces alike, that produces surface coatings with finely tunable nanoscale roughness and identical surface chemistry. Coatings with different degrees of roughness were characterized with regard to their morphology, charging, and wetting properties, and the results were correlated with the stability of emulsions prepared with coated particles of different roughness. We find that the maximum capillary pressure, a metric of the emulsions' resistance to droplet coalescence, varies significantly and in a nonmonotonic fashion with particle roughness. Surface topography and contact angle hysteresis suggest that particle roughness benefits the stability of our emulsions as long as wetting occurs homogeneously (Wenzel regime), whereas the transition toward heterogeneous wetting (Cassie-Baxter regime) is associated with a loss of stability.     

Mechanisms of Enhanced Oil Recovery by Surfactant-Induced Wettability Alteration

Different measurements were conducted to study the mechanisms of enhanced oil recovery (EOR) by surfactant-induced wettability alteration. The adhesion work could be reduced by the surfactant-induced wettability alteration from oil-wet conditions to water-wet conditions. Surfactant-induced wettability alteration has a great effect on the relative permeabilities of oil and water. The relative permeability of the oil phase increases with the increase of the water-wetness of the solid surface. Seepage laws of oil and water are greatly affected by surfactant-induced wettability alteration. Water flows forward along the pore wall in the water-wet rocks and moves forward along the center of the pores in the oil-wet rocks during the surfactant flooding. For the intermediate-wet system, water uniformly moves forward and the contact angle between the oil–water interface and the pore surface is close to 90°. The direction of capillary force is consistent with the direction of water flooding for the water-wet surface. While for the oil-wet surface, the capillary force direction is opposite to the water-flooding direction. The highest oil recovery by water flooding is obtained at close to neutral wetting conditions and the minimal oil recovery occurs under oil-wet conditions.     

Comparison of residual oil cluster size distribution, morphology and saturation in oil-wet and water-wet sandstone

We imaged an oil-wet sandstone at residual oil saturation (S(or)) conditions using X-ray micro-tomography with a nominal voxel size of (9 μm)(3) and monochromatic light from a synchrotron source. The sandstone was rendered oil-wet by ageing with a North Sea crude oil to represent a typical wettability encountered in hydrocarbon reservoirs. We measured a significantly lower S(or) for the oil-wet core (18.8%) than for an analogue water-wet core (35%). We analysed the residual oil cluster size distribution and find consistency with percolation theory that predicts a power-law cluster size distribution. We measure a power-law exponent τ=2.12 for the oil-wet core which is higher than τ for the water-wet system (τ=2.05), indicating fewer large clusters in the oil-wet case. The clusters are rough and sheet-like consistent with connectivity established through layers in the pore space and occupancy of the smaller pores; in contrast the clusters for water-wet media occupy the centres of the larger pores. These results imply less trapping of oil, but with a greater surface area for dissolution. In carbon storage applications, this suggests that in CO(2)-wet systems, capillary trapping is less significant, but that there is a large surface area for dissolution and reaction.     

AFM study of mineral wettability with reservoir oils

Wettability plays a key role in determining fluid distributions and consequently the multiphase flow and transport in petroleum reservoirs. Many crude oils have polar organic components that collect at oil-water interfaces and can adsorb onto the mineral surface if the brine film breaks, rendering the medium oil-wet or mixed-wet. Mica and silica surfaces have been aged with brine and crude oils to induce oil component adsorption. Bulk oil is eventually replaced by water in these experiments by washing with common solvents without ever drying the mineral surface. The organic deposit on the mineral surface is studied by atomic force microscopy in the tapping mode under water. Drying the surface during the removal of bulk oil induces artifacts; it is essential to keep the surface wet at all times before atomic force microscopy or contact angle measurement. As the mean thickness of the organic deposit increases, the oil-water contact angle increases. The organic deposits left behind after extraction of oil by common aromatic solvents used in core studies, such as toluene and decalin, are thinner than those left behind by non-aromatic solvents, such as cyclohexane. The force of adhesion with a probe sphere for minerals aged with just the asphaltene fraction is similar to that of the whole oil. The force of adhesion for the minerals aged with just the resin fraction is the highest of all SARA (saturates, aromatics, resins, and asphaltenes) fractions.     

Kinetic study of heavy crude oils by thermal analysis

The present work investigates the thermal behavior and kinetic of four types of petroleum samples: a medium crude oil—P1, one heavy oil—P2, and two extra heavy oils—P3 and P4 by TG, DTG, and DSC methods. Thus, this study may contribute to the characterization of petroleum with different °API values.     

A Study of Thin Liquid Films as Related to the Stability of Crude Oil Emulsions

In this paper, we report the influence of surface-active compounds on the stability of crude oil emulsions using the apparatus designed for bilayer lipid membrane studies. The results obtained show that natural surface-active materials in crude oil, such as petroleum acids and asphaltenes, play a pivotal role. The ionized acids formed by the reaction between the petroleum acids and the alkali can decrease the interfacial tension and accelerate the thinning as well as the breakdown of the thin liquid film. The asphaltenes can adsorb onto the interface and improve the stability of the film. The order of the stability of the films between crude oil and alkaline solutions is found to be as follows: crude oil with asphaltenes removed (ii) 相似文献   

Effect of varying the oil phase on the behavior of pH-responsive latex-based emulsifiers: demulsification versus transitional phase inversion

Sterically stabilized polystyrene latexes (previously described by Amalvy, J. I.; et al. Chem. Commun. 2003, 1826) were evaluated as pH-responsive particulate emulsifiers for the preparation of both oil-in-water and water-in-oil emulsions. The steric stabilizer was a well-defined AB diblock copolymer where A is poly(2-(dimethylamino)ethyl methacrylate) and B is poly(methyl methacrylate). Several parameters were varied during the emulsion preparation, including the polarity of the oil phase, the latex concentration, surface concentration of copolymer stabilizer, and solution pH. Nonpolar oils such as n-dodecane gave oil-in-water emulsions, and polar oils such as 1-undecanol produced water-in-oil emulsions. In both cases, these emulsions proved to be stimulus-responsive: demulsification occurred rapidly on adjusting the solution pH. Oils of intermediate polarity such as methyl myristate or cineole led to emulsions that underwent transitional inversion on adjusting the solution pH. All emulsions were polydisperse and typically ranged from 40 to 400 microm diameter, as judged by optical microscopy and Malvern Mastersizer measurements. Critical point drying of the emulsion droplets, followed by scanning electron microscopy studies, confirmed that the latex particles were adsorbed as a single monolayer at the oil/water interface, as anticipated.     

Further Investigation into the Stability of Water-in-Crude Oil Emulsions Formed in Burgan Oilfield: Effect of Toluene,Resins to Asphaltenes Ratio,and Surfactant

Factors controlling the formation and stabilization of water-in-crude oil (w/o) emulsions in oil fields are of great concern to the petroleum industry for the economic development of underground oil reservoirs. Controlling and minimizing the formation of w/o emulsions and demulsification of water from emulsions are also important for environmental development. Because of its importance, the mechanisms, formation, and stability of w/o emulsions have received considerable attention. This article deals with some of the factors responsible for the formation and stabilization of w/o emulsions formed in Burgan oil field in Kuwait. Some of the factors investigated in this study are the naturally occurred surface active components of crude oils such as asphaltenes and resins. Stability of emulsion samples with resins to asphaltenes ratio (R/A) contents of 3, 5, 9, 12, and 20 has been studied. It was found that Emulsion tightness is correlated with resins to asphaltene content of the sample. As the R/content increases the emulsion becomes unstable. The effect of additives such as toluene and dodecyle benzene sulfonic acid (DBSA) on the stability of various emulsion samples collected from oil field are also reported. A 2 wt% of DBSA was found to resolve all the water from emulsion samples collected from Burgan oilfield.