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Calcite and barite are two of the most common scale minerals that occur in various geochemical and industrial processes. Their solubility predictions at extreme conditions (e.g., up to 250 °C and 1500 bar) in the presence of mixed electrolytes are hindered by the lack of experimental data and thermodynamic model. In this study, calcite solubility in the presence of high Na2SO4 (i.e., 0.0407 m Na2SO4) and barite solubility in a synthetic brine at up to 250 °C and 1500 bar were measured using our high-temperature high-pressure geothermal apparatus. Using this set of experimental data and other thermodynamic data from a thorough literature review, a comprehensive thermodynamic model was developed based on the Pitzer theory. In order to generate a set of Pitzer theory virial coefficients with reliable temperature and pressure dependencies which are applicable to a typical water system (i.e., Na-K-Mg-Ca-Ba-Sr-Cl-SO4-CO3-HCO3-CO2-H2O) that may occur in geochemical and industrial processes, we simultaneously fit all available mineral solubility, CO2 solubility, as well as solution density. With this model, calcite and barite solubilities can be accurately predicted under such extreme conditions in the presence of mixed electrolytes. Furthermore, the 95% confidence intervals of the estimation errors for solution density predictions are within 4 × 10-4 g/cm3. The relative errors of CO2 solubility prediction are within 0.75%. The estimation errors of the saturation index mean values for gypsum, anhydrite, and celestite are within ±0.1 and that for halite is within ±0.01, most of which are within experimental uncertainties. [ABSTRACT FROM AUTHOR]

Steamflooding is a widely used technique for heavy-oil recovery. Scale control during steamflooding, however, can be challenging because the high temperature of the steamflood can decompose thermally unstable inhibitors and/or lead to the precipitation of metal-inhibitor pseudoscale. In this paper, we present the analysis of the scaling risk and scale inhibition for a pilot steamflood project in a Middle Eastern oil field. The formation of this field is a dolomite formation interbedded with anhydrite (CaSO4) streaks. Anhydrite has been observed to be the predominant scale form. Anhydrite scale was presumably formed by the increased production-system temperature resulting from steamflooding and/or the mixing of steam condensate with connate water at equilibrium with calcium sulfate minerals at lower temperature and higher solubility. Anhydrite is inherently difficult to control because of its high solubility and the high-temperature (HT) conditions under which it forms. Compared with barite and calcite, only limited knowledge has been acquired for anhydrite control. To predict the scaling tendency and inhibitor need in different wells of this field with different supersaturation levels and temperatures, a scalingrisk model has been developed. To build such a model, detailed and revised laboratory procedures have been developed to study nucleation and precipitation kinetics of anhydrite at 125-175°C, different supersaturation, different water composition, and long reaction time. Predictions of this scaling-risk model suggest a saturation index (SI) of 0.8 as a critical SI for anhydrite control at >125°C. For example, when the SI is above 0.8, anhydrite will be difficult to control in the presence of threshold inhibitor. Model predictions were benchmarked with the water-chemistry data from a total of more than 20 wells from this field, and were found to be consistent with field observations of scale occurrence in different wells. With the recommended inhibitor concentrations, anhydrite scale has been controlled in this field, which provides validation that the proposed scaling-risk model is a powerful tool to optimize the scale-treatment plan for anhydrite. [ABSTRACT FROM AUTHOR]

Barite (BaSO4) is one of the common scales in oil-and-gas production. Extensive work has been conducted to study barite nucleation and inhibition at temperatures below 100°C. However, with the advance in deepwater exploration and production (E&P) which can encounter high-temperature (HT) conditions, a better understanding of barite-scaling risk at HT (e.g.,>150°C) becomes essential. In this paper, a systematic study was conducted to explore barite nucleation kinetics from 70 to 200°C in synthetic brines containing phosphonate (0-10 ppm) or polymeric (5-10 ppm) scale inhibitors. A 2-hour protection time with or without any detectable barite nucleation was used to define the scaling risk. To detect barite nucleation, two novel apparatuses were developed--a modified dynamic flow loop and a batch reactor. The modified dynamic flow loop has a retention time of up to 4 hours and is ideal to carry out experiments at higher than 100°C. Ba concentrations in the effluents were monitored to determine barite nucleation more precisely compared with traditional "tube blocking" technique. The new batch reactor uses our newly developed laser-detection method, a transparent pressure tube, and an oil bath. The transparent pressure tube allows laser light to pass through and can withstand 150-psi pressure at 175°C, therefore providing an efficient approach to study the precipitation kinetics of scales and to evaluate inhibition efficiency of inhibitors at HT. Constant inhibitor-concentration isopleths of diethylenetriamine pentamethylene phosphonic acid (DTPMP) for barite inhibition were constructed on the basis of our experimental data. Finally, a semiempirical model that is based on data of barite nucleation and inhibition kinetics from this study and previous work was built to predict scaling risk of barite at different physicochemical conditions. This model covers a wide range of temperature (from 4 to 200°C) and brine compositions. It also covers the effect of Ba2+-SO2- 4 ratio in solution, common cations (e.g., Ca2+), and thermodynamic hydrate inhibitors on barite precipitation. Model precipitations were found to be consistent with field observations. The results of this study can guide the design of barite-scale treatment for HT oil-and-gas production. [ABSTRACT FROM AUTHOR]