Sulphonated polymers are used in oilfield for scale inhibition. In this study, Al-sulphonated polycarboxylic acid (SPCA) hybrid nanoparticles were prepared by an environmentally friendly approach. Particle size of these materials was controlled at about 80 nm by applying hydrothermal synthetic method with urea as slow neutralization agent. Reaction parameters such as concentration of salt solution, reaction time, urea concentration and ionic strength were investigated to optimize nanoparticle synthesis. The mobility of Al-SPCA hybrid nanoparticles decreases dramatically in 1% (w/w) KCl solution. Using phosphino-polycarboxylic acid (PPCA) as dispersant, nanoparticles were well suspended in 1% KCl solution. Absorption of PPCA to hybrid nanoparticles increases its negative surface charge and decreases particle deposition. The retention and long term flowback performance of hybrid nanoparticles were compared with the neat chemical squeeze simulation in ground core column experiments. The results showed that the slow release of sulphonated polymer from hybrid nanoparticles in porous medium leads to an enhanced squeeze treatment efficiency and successful inhibitor treatment in the oil field.
Large quantities of hydrate inhibitors, such as methanol, MEG (ethane 1, 2 diol), and TEG (triethylene glycol) are used to prevent gas hydrate formation during production from a gas/oil well. Due to environmental and economic concerns, MEG is often regenerated via a thermal vacuum distillation process. The hydrate inhibitors adversely enhance scale formation. The impact of temperature and concentration on mineral scale formation during MEG regeneration is largely unknown. The solubility of barite and halite in methanol/brine and MEG/brine solution was measured up to 473.15 K (200 °C ) and 6.6 MPa (1000 psia) to evaluate the impact of high temperature on mineral scale formation in hydrate inhibitor/brine solutions. A model is developed to assist the process design to prevent scaling risk during MEG regeneration. The ?unified theory? of electrolytes developed by one of the authors (EDJ), for prediction of the standard state thermodynamics properties of electrolytes to extreme temperatures and pressures, has been adapted to model the effect of temperature and pressure on mineral salt solubility in methanol, ethanol and MEG/brine solutions. The model requires knowing the Gibbs free energy of hydration at some temperature, usually 298.15 K (25 °C), and only two previously determined constants for each electrolyte. Once these constants are fixed, the model can be used to predict the standard state partial molar Gibbs free energies of electrolytes up to supercritical temperatures. The temperature and pressure behavior of electrolytes can now be accurately predicted from existing low temperature data alone. A modification of Pitzer's model for activity coefficients is also used to account for the effect of mixed electrolytes on solubility in cosolvent/brine systems. The combined model will be applied to typical reboiler systems in use on off-shore platforms and on shore.
Calcium carbonate and iron carbonate scales are widely observed in oil and gas production. Scale formation can be useful for corrosion control; however, excessive scale buildup can lead to severe production loss. What is called calcite scale in the field is almost always a solid solution of iron in calcite. Yet little attention has been paid to the precipitation of these mixed calcium-iron carbonate scales. As a result, knowledge of the formation and inhibition of mixed calcium/iron scales is very limited.
Normally, calcite scale formation is readily inhibited, whereas siderite inhibition is notoriously difficult. The solid-solution transition from predominantly calcite to predominantly siderite properties is unknown. Besides, although the solubility of mixed scale can differ by several orders of magnitudes from the solubility of its pure salts, scale prediction models are normally developed based on the data from pure solids. Finally, the incorporation of iron into calcite solid dramatically alters the kinetics of scale growth, as will be illustrated.
A series of experiments were performed to precipitate mixed iron-calcium carbonate (FexCa1-XCO3), ranging from calcium-rich to iron-rich. The experiments were conducted at 7.3±0.2 pH in 0.5 M NaCl at 55 oC. The work was performed with a new constant composition method, modified to handle oxygen sensitive ferrous carbonate scale and solid solutions.
Based upon the experimental results and a flux-based theoretical derivation, a new correlation in a form of a logistic function has been developed to predict the composition of FexCa1-xCO3 as a function of the aqueous composition. The model is an excellent representation for all of the experimental results, with R2 greater than 0.97. The correlation and methods developed in this work can readily be adapted to other mixed scale systems. Laboratory results will be compared with field observations and the consequences discussed.
In order to assess scaling risk in pipes, a better understanding of scale deposition kinetics on steel surface under realistic and complex oil field condition is needed. In this paper, we introduce the development of a novel CaCO3 pre-coated steel tubing for studies of CaCO3 crystal growth kinetics and inhibition kinetics at oilfield conditions. This approach provides a relatively stable surface area and eliminates the limits of laboratory batch experiments. Initially, the heterogeneous precipitation rate of CaCO3 from a supersaturated solution (Calcite SI=0.3-0.7) was evaluated at specific temperatures (60-80???C), linear velocities (0.01-0.75 cm/sec), and ionic strengths (0.1-1M). The curve fitted heterogeneous precipitation rate constant, kppt, ranged from 10 -5 to10 -4 cm/sec. The results are comparable to that calculated from the Sieder and Tate equation, which indicates that the crystal growth was dominated by mass transfer rate. With the injection of scale inhibitors for one hour through the pre-coated tubing, the calcium carbonate precipitation can be prevented for days, and the crystal growth rate can be significantly slowed down. Not only does this study contribute to the limited data base of scaling kinetics in actual flowing pipes, but also provides a new approach to better understand the inhibitor reaction with the subsurface. The approach and results will assist in the prediction of scaling risk as a function of brine composition, well conditions and scale inhibitor composition, which will improve our ability to predict the severity of scale risk, including the rate of scaling, minimum blockage time, and thus the minimum inhibitory concentration needed in actual flowing pipes.
The ultra-high temperature (150-250oC), pressure (1,000-2,000 bar, 15,000 to 30,000 psi) and TDS (>300,000 mg/L) in deepwater oil and gas production pose significant challenges to scaling control due to limited knowledge of mineral solubility, kinetics and inhibitor efficiency at these extreme conditions. Prediction of thermodynamic properties of common minerals is currently limited by lack of experimental data and inadequate understanding of modeling parameters. In this study, a new apparatus was built to test scale formation and inhibition at high temperatures and pressures. Solubilities of two common minerals, barite and calcite, were tested at temperature up to 250oC, pressure up to 1,500 bar (22,000 psi) and ionic strength up to 6m in solutions with elevated concentrations of mixed electrolytes (e.g., calcium, magnesium, sulfate and carbonate) representing the maximum range of interferences expected (95%CI) in oil and gas wells. As an attempt towards experimentally determining mineral solubility at high temperature, pressure and salinity, not only does this study contribute to the extremely limited data base, but it also provides a reliable approach for evaluating and adjusting model predictions at extreme conditions. Predictions by a thermodynamic model based on Pitzer's ion interaction theory were evaluated using experimental data. The dependence of Pitzer's coefficients for ion activity coefficients on temperature and pressure was examined and incorporated into the scale prediction model, whose prediction is consistent with both experimental and literature data at all conditions tested.
This paper presents a quantitative study of scale inhibitor thermal stability with regard to their potential application in high temperature wells. Systematic experiments have been conducted to investigate: (1) the influence of thermal aging on phosphonate and polymeric inhibitors at 200 °C, (2) the time (minutes to days) and temperature (up to 200 °C) dependence of inhibitor thermal degradation, (3) the impact of stainless steel and iron on the degradation of inhibitors at high temperatures, (4) the difference in aging tests with inhibitors in solution and that adsorbed on core materials, and (5) the effectiveness of a chelating agent to prevent the catalytic degradation of scale inhibitor by metal ions. The results enable a more accurate understanding of thermal degradation and provide a comprehensive guidance on the selection and placement of scale inhibitors for high temperature oil and gas production.
Lu, Haiping (Rice University) | Kan, Amy (Rice University) | Zhang, Ping (Rice University) | Yu, Jie (Rice University) | Fan, Chunfang (Rice University) | Work, Sarah (Rice University) | Tomson, Mason B. (Rice University)
Calcium sulfate is one of the major mineral scales in oil and gas production. Hemihydrate (CaSO4•0.5H2O) and anhydrite (CaSO4) are the predominant sulfate scales formed at high temperature, while gypsum (CaSO4•2H2O) scale may form at low temperatures (<~45°C). However, it has been shown in this study that anhydrite can form at low temperature in the presence of excess amounts of monoethylene glycol (MEG), and this may occur during offshore production with long tie-backs. The prediction and prevention of calcium sulfate scales requires knowledge of the phase behavior of the three major phases of calcium sulfate.
The phase behavior of different calcium sulfate phases is related to the supersaturation state, temperature, and fugacity of water. In this study, the effect of a common hydrate inhibitor, MEG, on calcium sulfate solubility and phase behavior was investigated. This study was run with NaCl/CaSO4/MEG/H2O solutions at 0-6 molality (M) NaCl and 0-95 wt% MEG at 4-70°C. Three approaches were taken to determine the kinetics of calcium sulfate phase transition at various temperatures, ionic strengths, and MEG concentrations: (1) dissolution of gypsum, (2) dissolution of anhydrite, and (3) nucleation and precipitation of calcium sulfate by mixing calcium- and sulfate-containing solutions. The effect of scale inhibitors on phase transition was also evaluated. Phase transition of gypsum to anhydrite was observed in the presence of high concentrations of NaCl and MEG, regardless of the experimental approach. The transition boundary of temperature and concentrations of NaCl and MEG can be estimated from solubility of calcium sulfate and the fugacity of water. The inhibition mechanism of hexamethylene diamine tetra (methylene phosphonic acid) (HDTMP), one of the most effective inhibitors for calcium sulfate scale, was also tested by investigating the kinetics of precipitation and inhibition of calcium sulfate.