Summary Significant progress has been made toward developing a quantitative understanding of the inhibitor/rock interaction. In this study, four common oil field inhibitors (three phosphonates and one polyacrylate) are compared using carbonate-rich formation material. In addition to calcite (CaCO3) in the reservoir rock, several calcium inhibitor (Inh) solid phases are also important. Two reactions are central to the inhibitor retention in carbonate-rich formation: first, reduction of calcite dissolution because of surface poisoning by the Ca-Inh coating; and second, precipitation of Ca-Inh solid with either low Ca or high Ca stoichiometry. For NTMP, an acidic Ca-NTMP salt is formed at a low-pH environment. In addition, two crystalline Ca-NTMP phases and an amorphous Ca-NTMP salt may form, depending on the aquatic environment. Quantitative relationships between types of inhibitors, inhibitor acidity and concentration, and kinetics of calcite dissolution and calcium-phosphonate precipitation are developed. Consequences of the observations on squeeze design and scale inhibition will be discussed. Introduction The reactions of inhibitor with formation rock determine the inhibitor retention and release following an inhibitor squeeze. There are several aspects to understanding and optimizing, in a predictable manner, inhibitor squeeze designs. Earlier efforts have focused on describing what happens and when to resqueeze.1,2 More recent papers have advanced the knowledge of inhibitor reactions under various production conditions.3–13 Missing in previous inhibitor/core interaction studies have been the order of the reactions, kinetics, and solid-phase stoichiometry following the inhibitor/core reaction. A question with inhibitor/core reactions is to what extent the reaction will be quenched by adsorbed inhibitors. It is also necessary to know the differences among inhibitors, how to optimize a squeeze design, and if there is an optimum inhibitor concentration and acidity. A primary objective of this study is to develop mechanistic understanding of how inhibitors react with core material and to develop a methodology to predict and control inhibitor/core reactions. In the following, the chemistry of inhibitor/carbonate-rich rock interaction has been characterized for four commonly used oilfield-scale inhibitors. Inhibitor Solution Speciation and Metal Salt Solubilities. To predict the fate of inhibitors in the diverse brine compositions that occur in production fluids, it is necessary either to know or to be able to predict the simple acid-base and complexation equilibrium of inhibitors and divalent metals, such as calcium, magnesium, barium, and iron, vs. T and TDS. In Table 1 is listed the ionization and complexation stability constants for three phosphonic acids: aminotri(methylene phosphonic acid or NTMP, diethylenetriamine penta(methylene phosphonic acid or DTPMP, and bis-hexamethylenetriamine penta(methylene phosphonic acid or BHPMP, and one polyacrylic acid (phosphinopolycarboxylic acid or PPCA). These inhibitors are some of the most common oilfield-scale inhibitors. Note that the unit of polymer concentration used in calculating PPCA speciation is expressed as the acrylic acid monomer (A), which may be extended to polymers of different sizes. Similarly, the stoichiometry of Ca-PPCA salt is expressed as three Ca and two acrylic acid trimers. To our knowledge, this is the first attempt to establish a simple set of substi-tuent constants for inhibitor acids at realistic oilfield conditions. At 1.0 M ionic strength and 70°C, bCa=0.56 for NTMP, 0.62 for DTPMP, and 0.38 for BHPMP (see Table 1). This would correspond to a stability constants of 101.12, 101.24, and 10 0.76 M–1 for the complexation of Ca27 with a dinegative phosphonate ion in the order of NTMP, DTPMP, and BHPMP, respectively. This is comparable to the stability constants of Ca/methyl and aminomethyl phosphonates.14 The average stability constant of Ca with 12 common monophosphonates is 101.55+0.14 M-1 at 0.1 M I and 25°C. It should be noted that the stability constant for Ca2+HPO42– ?CaHPO40 is approximately 101.3 M-1 at 1 M I and 25°C. The difference between the stability constants of the polyphosphonates measured by this research group and those reported in the literature may be caused by the electrostatic effect of these molecules, because of an ionic strength effect, or related to more complicated relations of structure, but clearly the complexation is mostly electrostatic in origin. Using these speciation models, we are able to establish the solubility products of various metal phosphonate and metal-polymer solubility products (Table 2) and their ionic strength and temperature dependence using statistical programs to correlate the laboratory-measured solubilities.15–17 For all three phosphonate salts and the Ca-PPCA salt, we typically observed the formation of a high-solubility amorphous phase of metal inhibitor salt when mixing the inhibitor with calcium at high concentrations.15–20 The amorphous high-solubility material will eventually develop into a crystalline phase with much lower solubility, often by flowing brine over the metal inhibitor salt by a membrane filter to remove the readily solubilized amorphous Ca-Inh salt. The crystalinity of both Ca-NTMP and Ca-DTPMP solid phases has been confirmed by XRD analyses. The solubilities of Ca-NTMP and Ca-DTPMP are very similar, while Ca-BHPMP is significantly more soluble than that of Ca-NTMP (approximately seven times higher than that of Ca-NTMP at 70°C, 1 M ionic strength, 4000 mg/l Ca, and 5.5 pH). The solubility of Ca-PPCA is lower than Ca-BHPMP and higher than Ca-NTMP. Note that the solubility product of Fe-NTMP is many orders of magnitude lower than Ca-NTMP. Therefore, the solubility of Fe-NTMP may also play a significant role in controlling the fate of phosphonates during squeeze and production, even though iron concentration is typically much lower than the calcium concentration in brine.21
Summary 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 from experimental solubility measurements of halite, barite, gypsum, calcite, and carbonate equilibrium chemistry. The ion-cosolvent 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 and 50°C as well as between 1 and 6 M ionic strength. Working equations that can be used in gas and oil production to calculate the effect of cosolvents on scale formation are presented. Details about how to predict hydrate-inhibitor-induced scale formation and case studies that demonstrate the severity of methanol on scaling tendency are also discussed. Finally, barite nucleation and kinetics are studied in the presence and absence of methanol. A semi-empirical equation to predict the nucleation time is proposed. Preliminary studies of scale-inhibitor efficiency in the presence of methanol are also discussed. At high methanol concentration, scale inhibition may not be possible because of precipitation of metal-inhibitor salt. Glycols have a less adverse effect than methanol on both mineral scale formation and inhibition. Introduction Methanol, ethylene glycol, and triethylene glycol are industrial solvents and raw materials for a variety of processes. In the oil and gas industries, methanol, ethylene glycol, and triethylene glycol are often used to inhibit gas-hydrate formation during production. Gas hydrate is a crystalline solid consisting of a gas molecule surrounded by a cage of water molecules, which forms at certain high-pressure and low-temperature regimes. Gas-hydrate formation is particularly troublesome for offshore gas wells, where the producing temperature is low because of both adiabatic expansion of gas and seawater cooling. Once gas hydrate forms, it can plug up the well and prevent gas production. One economic solution to prevent hydrate formation is to inject a large quantity of methanol, ethylene glycol, or triethylene glycol. These organic solvents are thermodynamic inhibitors (i.e., they increase the thermodynamic solubility of gas hydrate). This type of inhibitor is only effective at high cosolvent concentrations. Unfortunately, the use of high cosolvent concentration has an adverse effect on scale formation. because the mineral salts are generally less soluble in the cosolvent. Production from reservoir oilfield brines are often close to saturation as they enter a well; therefore, even a small amount of added methanol or ethanol 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 less adverse effect on mineral-salt-scaling tendency.
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.
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