The rate of excited-state proton transfer from four cyano-substituted 2-naphthols was measured in H2O and D2O by picosecond time-resolved fluorescence. The excited-state acidity constant, pK a*, was calculated and compared with previous results and was found to be substitution-dependent, as predicted by the charge-transfer theory. The isotope effect was evaluated for all the compounds of the series. As reported for many other hydroxyaromatic compounds, this effect was more important for the dissociation rate constant than for the recombination rate constant.

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A number of factors are known to contribute to and enhance water-in-crude oil emulsion stability. Organic-based and naturally occurring materials (e.g., asphaltenes, resins, naphthenic acids, waxes, etc.) have received a great deal of attention regarding their role in stabilizing and, at times, destabilizing petroleum-based emulsions. While these materials are known to reside at the oil−water interface, inorganic constituents are likewise known to contribute to emulsion stability and have been shown to also reside at the oil−water interface. To study the inorganic components in unresolved oilfield emulsions, numerous field samples were subjected to the American Society for Testing and Materials D4807-88 procedure that involves a hot toluene filtration. This method effectively removes the organic phase and isolates the inorganic components that may have also played a role in emulsion stabilization. The residual inorganic residues were initially characterized by a combination of scanning electron microscopy (SEM) and energy-dispersive spectrometry (EDS). Following up on the initial report where several samples contained highly organized inorganic structures, called salt spheres or salt scaffolds, this study takes a closer look into their compositional makeup using enhanced EDS capability with the addition of digital compositional mapping (DCM). Salts with low solubility-product constants appear to outline once existent water-in-crude oil droplets and, thus, may have played a key role in emulsion stabilization. Sodium chloride crystals often dominate the interior of these structures, and it is this entity that upon further examination was found to be unstable with regard to prolonged exposure to humidity. In comparison to dry or treated sales oils, inorganic solid levels from the oil−water interface of two oilfield separators were found to be considerably higher, with one of the samples containing an abundance of well-defined salt spheres. By use of the DCM technique, the separator sample was shown to contain salt spheres with an outer coating of strontium sulfate.

This paper describes field experience and lessons learned from scale-control operations in a deepwater development in the Gulf of Mexico. The injection of seawater for reservoir pressure maintenance resulted is a high barium-sulfate scaling tendency upon breakthrough of injection water which meant that it was critical to have effective scale management achieve high hydrocarbon recovery for this field. Use of conventional, water-based squeezes in the field did not deliver the squeeze lifetime expected and for some treatments resulted in production impairment. Hence, based upon risk mitigation, an alternative scale squeeze program was required this alternative program was supported by an extensive set of laboratory tests including reservoir condition coreflooding, based on these laboratory results it was decided to apply squeeze treatments of aqueous scale inhibitor proceeded by mutual solvent to reduce the risk of relative permeability damage and increase squeeze life by enhancing inhibitor adsorption. Aspects of well cleaning prior to scale squeeze deployment will be outlined as this has proved critical to the success of scale squeeze treatments in these wells which have an asphaltene tendency. Results from two of the five current scale squeeze treatments are presented to demonstrate that an integrated evaluation, treatment program design using squeeze design software, implementation and monitor (critical ions, inhibitor residuals, suspended solids) approach can being significant benefit to this challenging aspect of flow assurance. The paper will explore in detail the issues associated with inhibitor-squeeze treatment selection, deployment, monitoring in deepwater Gulf of Mexico and is a good example of implementation of best-practice sharing from another oil basin (Angola, West Africa) were the same operator overcome similar issues.

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