TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractOil field scale treatments can become more difficult when working with deeper non-conventional wells. Inhibitor squeeze is generally the most efficient scale treatment technology. However, inhibitor squeeze treatment is based more on experiences than mechanistic understanding of how the chemical interacts with formation rock and how it flows back.Better mechanistic understanding of the phosphonate/rock interaction is needed to derive innovative squeeze treatment for newer non-conventional wells. Significant progress has been made toward developing a quantitative understanding of the inhibitor/rock interaction, kinetics, stoichiometry, and equilibrium as inhibitors are injected into a formation and allowed to flow back. Four common oil field inhibitors (three phosphonates and one polyacrylate) are compared. In addition to calcite (CaCO 3 ) in the reservoir rock, at least three phosphonate phases appear to be important, a low Ca and a high Ca amorphous Ca-P salts and a crystalline Ca-P salt, where "P" refers to a phosphonate molecule. The inhibitor/rock interaction follows four sequential reactions: (1) Limited acid attack of calcite; (2) Formation of a monomolecular coverage of phosphonate; (3) Reduction of further calcite dissolution due to surface poisoning by the Ca-P coating; (4) Precipitation of Ca-P solid with either low Ca or high Ca stoichiometry. Quantitative relationships between type of inhibitors, inhibitor concentration and acidity, kinetics of calcite dissolution and calcium-phosphonate precipitation are developed for the first time using a rule-based automatic approach. Consequences of the observations on squeeze design and scale inhibition will be discussed.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractHydrate formation can be a serious problem in many gas production systems. Large volumes of hydrate inhibitors (e.g., methanol, ethanol, ethylene glycol, and triethylene glycol as cosolvent) are often added to control hydrate formation. Such practice has an adverse effect on scale formation since the mineral salts are generally less soluble in the cosolvent. Due to production from reservoirs oilfield brines are often close to saturation as they enter a well, and even a small amount of added methanol, ethanol, etc., is often sufficient to induce various minerals to precipitate. The scaling tendency of sparingly soluble mineral salts, e.g., calcite and barite, in methanol/brine and ethanol/brine solutions is observed to be orders of magnitude larger than in the brine alone. Halite scaling is also severely affected in the presence of methanol or ethanol. Ethylene glycol and triethylene glycol have a lesser adverse effect on mineral salt scaling tendency. There is no accepted methodology to correlate the effects of hydrate inhibitors on scale formation as there is for electrolytes. Similarly, the effect of hydrate inhibitor on scale inhibition with common inhibitors is not well known. In this paper, a semi-empirical approach is proposed to correlate the effect of hydrate inhibitors on scale formation and inhibition from experimental solubility measurements of halite, barite, gypsum, calcite and carbonate equilibrium chemistry. The ioncosolvent activity coefficients can be used directly in any solution speciation code to evaluate the effect of cosolvent on mineral scale formation. The validity of the equation has been tested between 4-50 ºC and 1-6 M ionic strength. Working equations that can be used in gas and oil production to calculate the effect of cosolvents on scale formation will be presented. Such equations have been incorporated into ScaleSoftPitzer V.4.0. ScaleSoftPitzer TM is a Microsoft TM Excel TM based program to predict scale tendency, specifically written for the oil and gas production systems. Details of using ScaleSoftPitzer V.4.0 to predict hydrate inhibitor induced
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