Scale asphaltene

Yet the statement of Professor Brill s question indicates the importance of flow assurance, particularly related to hydrates, waxes, scale, corrosion, and asphaltenes, in decreasing order of importance. In the Gulf of Mexico, for example, hydrates are considered to be the largest problem by an order of magnitude relative to the others. 

The liquid hydrocarbon causes separation of the asphaltenes and/or the resins from the feedstock leaving a deasphalted oil that contains substantially less sulfur and metals than the feedstock. On a commercial scale, propane is the most common solvent (Figure 7-21) and the units are designed to operate at 40 to 80°C (105 to 175°F) and at pressures of 400 to 550 psi with the solvent/ feedstock ratio usually falling in the range 5 1 to 13 1. 

Although the evidence available in the literature appears to indicate that the hydrocarbon structures and some features, such as the various condensed ring systems, in different petroleums are similar (from the asphaltenes and resins to the constituents of the oil fraction), the variety of source materials involved in petroleum genesis implies that, on an individual molecular scale, there may be substantial structural differences among the constituents of the various crude oils and bitumens. As well, the difficulty with which resins from one crude oil peptize (As in a colloid, the terms peptization, dispersion, and solubilization are often used interchangeably to describe the means by which asphaltenes exist within petroleum.) asphaltenes from a different crude oil, and the instability of the blend (5) are evidence for significant structural differences among the asphaltenes and resins of various crude oils. 

To quantify the concepts given above, it is necessary to devise a polarity scale related to solubility theory. Since the precipitating solvents for asphaltene separation are at the low end of the solubility parameter scale, it seems... 

In addition to the effects of crystal lattice energy, choice of solvent other than n-paraffins can also be important. For example, Corbett and Swarbrick (10) have shown that a number of oxygenated compounds can precipitate asphaltenes from petroleum residua in quantities varying from 12 wt % to 100 wt % on resid. Clearly, the shape of the precipitation curves for the different solvents should be different from that for n-paraffins and from each other. However, the use of a solubility parameter type of polarity scale should permit rationalization of the results when considered along with the solubility parameter of the particular solvent. 

The concept of asphaltenes is rooted in the solubility behavior of high-boiling hydrocarbonaceous materials in benzene and low-molecular-weight n-paraffin hydrocarbons. This behavior is a result of physical chemistry effects that are caused by a spectrum of chemical properties. This chapter has pointed out that by considering molecular weight and molecular polarity as separate properties of molecules, the solvent-precipitation behavior of materials derived from various carbonaceous sources can be understood. Future quantification of this approach probably can be achieved by developing a polarity scale based on solubility parameter. 

McKay s solvent sequence completely eluted the Wilmington asphaltenes but did not elute all the Athabasca asphaltene samples and had to be extended by additional solvent mixtures to obtain good sample recoveries (cf. Figure 2). For large scale preparative separations of asphaltenes, the asphaltenes were dissolved in benzene and eluted with the same solvent, omitting the cyclohexane step. This accelerated the operation, but at the same time, as expected, the percentage of the neutral fraction now increased from 20%-21% to approximately 28%-30%, in reasonable agreement with the bulk results from the cyclohexane experiments (see Table III). Table III also shows the additional solvent systems used. 

Table III. Preparative Scale Separation of Athabasca Asphaltenes on Ion Exchangers IRA-904 and A-15...

Gel Permeation Chromatography. More and more work with residua and asphaltenes is using GPC as a useful separation method for size separations of the heaviest fractions of bitumens and petroleum residua. In a manner similar to that used in polymer chemistry, attempts have been made to calibrate a GPC MW scale so that it may be brought into accord with MW measurements by other methods (e.g., VPO). In other words, we are trying to relate the peak value (Va) and statistical distribution of the MW across the... 

The molecular size distributions and the size-distribution profiles for the nickel-, vanadium-, and sulfur-containing molecules in the asphaltenes and maltenes from six petroleum residua were determined using analytical and preparative scale gel permeation chromatography (GPC). The size distribution data were useful in understanding several aspects of residuum processing. A comparison of the molecular size distributions to the pore-size distribution of a small-pore desulfurization catalyst showed the importance of the catalyst pore size in efficient residuum desulfurization. In addition, differences between size distributions of the sulfur- and metal-containing molecules for the residua examined helped to explain reported variations in demetallation and desulfurization selectivities. Finally, the GPC technique also was used to monitor effects of both thermal and catalytic processing on the asphaltene size distributions. 

In this study, six petroleum residua were characterized by a combination of preparative- and analytical-scale gel permeation chromatography (GPC). Each residuum was separated initially by pentane deasphalting into an asphaltene and maltene pair, both of which were separated further by... 

These two concepts have been proved on a laboratory scale, mainly for hydrogenation reactions but can be transposed to many gas-liquid catalyzed reactions. Interesting potential applications have been mentioned, such as asphaltene hydrocracking or nitrate and nitrites removal from drinking water by catalytic nitrate reduction. However, the characteristics of ceramic... 

Within oil-field emulsion breaking, the economics usually favor minimal heat input because light ends are not lost to the gas phase and fuel-gas consumption is minimized. Other significant effects caused by the addition of heat are an increased tendency toward scale deposition on fire tubes, an increased potential for corrosion in treating vessels, and a tendency to render asphaltenes insoluble (because of loss of light aromatic components), which may produce an interface pad problem. 

Experimental results show the high stability of INT-R1 catalyst when processing feedstocks with high metal, Conradson Carbon, and asphaltene content. Operating cycles of a least six months were demonstrated at bench scale using feedstocks with 400 ppm metals, 8 to 10 wt% Conradson Carbon and 8 %wt asphaltenes. Expected INT-R1 catalyst life with lighter feedstocks shows the feasibility of reaching a stable operation for more than one year with up to 100% metal retention on the catalyst. 

Hartley, P.G. and Scales, P.J., Electrostatic properties of polyelectrolyte modified surfaces studied by direct force measurement, Langmuir, 14. 6948, 1998. Rodrigues, E.A., Monteiro, P.J.M., and Sposito, G., Surface charge density of silica suspended in water-acetone mixtures, J. Colloid Interf. Sci.. 211, 408, 1999. Abraham, T. et al.. Asphaltene-silica interactions in aqueous solutions Direct force measurements combined with electrokinetic studies, Ind. Eng. Chem. Res., 41, 2170, 2002. 

Other solids can form in wells. These include asphaltenes and paraffins (waxes), coke, hydrates, inorganic scales, and corrosion products. Consideration of these is beyond the scope of this chapter. 

The lifetime of the emulsion (and the retention time in the full-scale separator) depends on the kind of stability mechanisms involved. There exist several possibilities of finding stabilizing agents (or solid fines) in either the crude oil itself or in added production chemicals. Among the indigenous stabilizers, asphaltenes/resins/ porphyrins are mentioned as possible candidates for the stabilization of... 

Most of the early methods developed for probing the relative stability of asphaltene and crude emulsions were centered on monitoring the amount or percentage of an emulsion which will phase separate on a macroscopic scale into a bulk continuous or disperse phase under the influence of gravity or a centrifugal field. These experiments are usu-... 

The time seale over which asphaltenic aggregates adsorb at water droplet-oil interfaces and begin to stabilize emulsions is extremely fast, of the order of seconds after the droplets are created by shear. This is not surprising when one considers the extremely short diffusion times required over short length scales. Typical droplet sizes produced in strong shear are of the order of micrometer or less when the Weber numbers are high (> 100-t). Thus, the diffusion times of asphaltenic aggregates with difftisivities of 10 cmVs over interdroplet separation distances of 1 om should be ... 

The time scale for the dynamic development of a cef in model asphaltene-heptane—toluene emulsions with water is illustrated in Fig. 19, in which solutions of Arab Heavy (AH) asphaltenes (0.5-1.0% w/w) in 40-50% toluene-in-heptol are emulsified with 30% water, and the cef is monitored as a fimction of time. As should be apparent, there is a characteristic time scale for the cef to rise markedly towards its steady-state value which varies with asphaltene concentration and solvation state of the asphaltenes. The time scale is most rapid at the limit of solubility (40% toluene) and with the higher concentration of asphaltenes (1% versus 0.5%). As concentration is reduced, the time required to reach the near-steady value decreases. Interestingly, it appears to be the same value, regardless of concentration (= 1.2 kV/cm). Also, as the toluene concentration is increased from 40 to 50%, the time scale increases and the long-term value of the cef decreases. This is consistent with a reduced driving force for adsorption of aggre-... 

This sample has been discussed elsewhere [78,79,92]. Table 33.1 shows the elemental analyses of the sample and the fractions, while Table 33.2 shows the proportions of the maltene and asphaltene fractions. Figure 33.7 shows LD-MS of a distillation residue of Syncrude sweet blend from the Athabasca tar sands, at different LPs and different HMA voltages (9 and 10 kV). At 30% LP, the spectra (1 and 2) were very weak and close to the ionization threshold at 40% LP, the maximum ion intensity shifted slightly to higher mass (m/z 300-400) and the upper mass limit moved to about m/z 5000 at 50% LP, the maximum ion intensity remained between 300 and 400 though off-scale, while the upper mass limit moved to m/z 20,000-30,000 with evidence of cluster ion formation. Figure 33.8 shows the Syncrude mass... 

These include liquid-liquid interfaces (micelles and emulsions), liquid-solid interfaces (corrosion, bonding, surface wetting, transfer of electrons and atoms from one phase to anodier), chemical and physical vapor deposition (semiconductor industry, coatings), and influence of chemistry on the thermomechanical properties of materials, particularly defect dislocation in metal alloys complex reactions in multiple phases over multiple time scales. Solution properties of complex solvents and mixtures (suspending asphaltenes or soot in oil, polyelectrolytes, free energy of solvation theology), composites (nonlinear mechanics, fracture mechanics), metal alloys, and ceramics. 

Next, a knowledge of the reservoir fluids is essential. This includes the fluid types (oil or gas) and the fluid properties. Fluid properties include carbon dioxide (CO ) or hydrogen sulfide (H S) content in gas, gravity of oil, paraffin and asphaltene contents, and volume and properties (ionic composition and scaling tendency) of produced water. 

Reservoir fluid sample analyses should be reviewed or conducted if analyses do not yet exist. Produced fluids can cause damage through deposition of wax or asphaltenes from oil or through scale formed from produced brine. Also, while well assessment continues, it may be found that fluids incompatible with the reservoir fluids, inducing organic deposition or scale formation, may have been introduced sometime in the well s past. 

Generally speaking, acid-removable skin is a reduction in permeability, caused by plugging or constriction in pore throats, that can be removed by acid. Non-acid-removable skin includes changes to the pore structure resulting in increased resistance to flow, such as wettability effects. Resistance to flow also may result from plugging by acid-insoluble materials, such as certain scales, paraffin (wax), and asphaltenes. 

The purpose of the preflush is to remove organic or inorganic scale from the wellbore tubulars prior to injection of the acid stage. An aromatic solvent, such as xylene, can be used to remove hydrocarbon deposits. For asphaltene deposits, specifically, terpene-based solvent solutions can be quite effective. Circulation of 5%-7.5% HCl downhole is adequate to remove rust and other inorganic scale for rust removal in particular, non-add (nearneutral) removal solutions exist and may be preferable at temperatures of MOT (60°C) and higher. 

There are some deposits that are not scale, but are related the sludges. Some sludges consist of considerable organic matter such as wax, asphaltenes, or tar. The deposits may be hard and crumbly, or soft and mushy. 

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