Lu, Alex Yi-Tsung (Rice University) | Ruan, Gedeng (Rice University) | Harouaka, Khadouja (Rice University) | Sriyarathne, Dushanee (Rice University) | Li, Wei (Rice University) | Deng, Guannan (Rice University) | Zhao, Yue (Rice University) | Wang, Xing (Rice University) | Kan, Amy (Rice University) | Tomson, Mason (Rice University)
Deposition of inorganic scale has always been a common problem in oilfield pipes, especially in raising safety risk and producing cost. However, the fundamentals of deposition mechanism and the effect of various surface, temperature, flow rate and inhibitors on deposition rate has not been systematically studied. The objective of this research is to reveal the process of barium sulfate deposition on stainless steel surfaces.
In this work a novel continuous flow apparatus has been set up to enable further investigation of deposition rate, crystal size and morphology and the effect of scale inhibitor. In this apparatus supersaturate barium sulfate solution is mixed and passed through a 3 feet stainless steel tubing with ID = 0.04 inch or 0.21 inch at 70 to 120 degree C. The barium concentration is measured at the effluent to quantify the concentration drop. After 1 to 200 hours the tubing is cut into pieces to measure the barite deposition amount and observe the barite crystal morphology using SEM.
Under the experimental conditions, the deposition rate along the stainless steel tubing can be modelled by second order crystal growth kinetics, the SEM micrograph also shows that most of deposited barite is micrometer sized crystals. The highest deposition rate happens at the beginning of the tubing even before the expected induction time of bariums sulfate. The results indicated that the deposition happens even before the mixed solution is expected to form particles, which suggest that the heterogeneous nucleation might be the dominate mechanism in the initial stage, then crystal growth takes place and governs the deposition.
The mechanism of scale attachment to tubing surface has never been well-understood. The apparatus in this work provides a reliable and reproducible method to investigate barium sulfate deposition. The findings in this research will enhance our knowledge of mineral scale deposition process, and aid the use of inhibitors in mineral scale control.
This paper discusses research on performance of scale inhibitors in the presence of ferrous ion. Iron ion is the most abundant heavy metal ion in wastewater and oilfield produced water. Fe(II) is the dominant form of iron ion in oil and gas wells due to the downhole high anoxic conditions. Fe(II) can form FeS and FeCO3 which will cause severe problems in production. Further, it is important to thoroughly investigate the inhibitor compatibility with these cations in oilfield as the existence of iron in solution effects on inhibitor chemistry.
In this research, Fe(II) effect on various scale inhibitors on barite was tested using an improved anoxic testing apparatus along with laser light scattering nucleation detection method. In this newly designed apparatus strict maintenance of anoxic condition is guaranteed by constant argon flow and switch valve to transfer solution. Moreover, the high Fe(II) tolerance concentration for common inhibitors were tested by varying Fe(II) concentrations from 50-100 mg/L at 90°C and near neutral pH conditions. Most scale inhibitors show good Fe(II) tolerance at experimental conditions, while the inhibition performance of phosphonates were significantly impaired by Fe(II). It is proposed that the formation of insoluble precipitates between Fe(II) and phosphonate is very likely the reason behind the observed significant impairment. Further, two methods to reverse the detrimental effect of Fe(II) on barite scale inhibitor performance is investigated and discussed here. First, a most common organic chelating agents used in oilfield, EDTA, was tested for its ability to reverse the detrimental effect of Fe(II) on scale. Secondly, Fe(II)/Inhibitor concentration ratio was changed so that remaining inhibitor in the aqueous phase would conduct the scale inhibition.
Harouaka, Khadouja (Rice University) | Lu, Yi Tsung (Rice University) | Ruan, Gedeng (Rice University) | Sriyarathne, H. Dushanee (Rice University) | Li, Wei (Rice University) | Deng, Guannan (Rice University) | Zhao, Yue (Rice University) | Wang, Xin (Rice University) | Kan, Amy T (Rice University) | Tomson, Mason (Rice University)
Calcium carbonate deposition experiments were carried out by pumping a brine solution through PTFE plastic, carbon steel, and 316 stainless steel tubing at 150°C and at a maximum SICaCO3 of 1.36. The kinetics of deposition were inferred from the variation of HCO3- concentration in the effluent with changing flow rate. The inhibition kinetics were determined before, during, and after the addition of NTMP inhibitor into the system. On the metal surfaces, deposition occurred within 10 minutes of the start of the experiment and had similar behavior with changing flow rate, whereas deposition did not begin on the PTFE surface until 30 minutes had passed. No more than 1ppm of NTMP was sufficient to completely halt deposition in the PTFE and stainless steel experiments, whereas up to 2 ppm of NTMP was required in the carbon steel experiment. The deposition kinetics were indistinguishable between the metal surfaces, and were ultimately similar on the smoother hydrophobic PTFE surface once an initial coating of scale had developed. The inhibition efficiency of the NTMP was negatively affected by the corrosion products produced in the carbon steel experiments, assumed to be primarily dissolved Fe (II). Inhibitor retention was higher in the metal surfaces than in the PTFE, possibly due to the preferential adsorption of the NTMP to the surface of the Fe rich steel tubing. Our results suggest that it is the hydrodynamics of brine in the tubing, controlled by flow rate, and the SI that are the main factors controlling scale deposition. Calcium carbonate scale attachment occurs via heterogenous nucleation directly onto the surface of the tube when the brine solution approaches oversaturation from a state of equilibrium with respect to calcium carbonate. The mechanism of inhibition in our system is likely to proceed through the formation of Ca- and Fe-NTMP complexes that either poison the growth surfaces of the scale, or drop the SI of the calcium carbonate by reducing the acitivity of free Ca in the brine.
Li, Wei (Rice University) | Ruan, Gedeng (Rice University) | Bhandari, Narayan (Rice University) | Wang, Xin (Rice University) | Liu, Ya (Rice University) | Dushane, H. (Rice University) | Sriyarathne, M. (Rice University) | Harouaka, Khadouja (Rice University) | Lu, Yi-Tsung (Rice University) | Deng, Guannan (Rice University) | Zhao, Yue (Rice University) | Kan, Amy T. (Rice University) | Tomson, Mason (Rice University)
Increasing production activities in sour environments with equipment and piping made of low corrosion- resistant carbon steel result in significant iron sulfides (FeS) corrosion and scaling problems. FeS scale control is challenging as FeS formation is favored in production water chemistry (extremely low solubility and fast precipitation kinetics) with complex phase transformations. Efficient chemical control of FeS scales has not been found. A polymeric compound containing amide or its derivative functionalities showed a promising effect by controlling the FeS particle size on a nano-meter scale at threshold quantities. The FeS scales were successfully managed by forming a stable FeS particle suspension in the aqueous phase without partitioning into the oil-water interface. Current development focuses on understanding the interactions between the polymeric-compound based dispersants and environmental factors such as the presence of an oil phase, as well as silica. In addition, performance improvement of the identified dispersants by new chemical additives has been explored. Our results show that biocides such as Tetrakis (hydroxymethyl) phosphonium chloride (THPS) may not be as effective as needed for FeS scale inhibition benefit. At the tested conditions, EDTA shows satisfactory FeS scale inhibition and dissolution performance. In addition, silica significantly affects wettability of FeS particles with part of the previously oil-wet FeS partitioning into the aqueous phase. The FeS inhibition and dissolution effects of EDTA are kinetically "poisoned" by silica; while FeS-dispersing effect of polymeric compounds remains unaffected. However, the previously-shown ability that polymer dispersants keep already-formed large size FeS particles in the aqueous phase is also impaired.
Kan, Amy T. (Rice University) | Dai, Joey Zhaoyi (Rice University) | Deng, Guannan (Rice University) | Ruan, Gedeng (Rice University) | Li, Wei (Rice University) | Harouaka, Khadouja (Rice University) | Lu, Yi-Tsung (Rice University) | Wang, Xin (Rice University) | Zhao, Yue (Rice University) | Tomson, Mason B. (Rice University)
Numerous saturation indices and computer algorithms have been developed to determine if, when, and where scale will form, but scale prediction can still be challenging since the predictions from different models often differ significantly at extreme conditions. Furthermore, there is a great need to accurately interpret the partitioning of H2O, CO2, and H2S in different phases, and the speciations of CO2 and H2S. This presentation is to summarize current developments in the Equation of State and the Pitzer models to accurately model the partitioning of H2O, CO2, and H2S in hydrocarbon/aqueous phases and the aqueous ion activities at ultra high temperature, pressure and mixed electrolytes conditions. The equations derived from the Pitzer ion-interaction theory have been parametrized by regression of over 10,000 experimental data from publications in the last 170+ years using a genetic algorithm on the super computer, DAVinCI. With this new model, the 95% confidence intervals of the estimation errors for solution density 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 calcite, barite, gypsum, anhydrite, and celestite are within ± 0.1, and that for halite is within ± 0.01, most of which are within experimental uncertainties. This model accurately defines the pH of the production tubing at various temperature and pressure regimes and the risk of H2S exposure and corrosion. The developed model is able to predict the density of soluble chloride and sulfate salt solutions within ±0.1% relative error. The ability to accurately predict the density of a given solution at temperature and pressure allows one to deduce when freshwater breakthrough will occur. Lastly, accurate predictions can only be reliable with accurate data input. The need to improve accuracy of scale prediction with quality data will also be discussed.
Zhang, Fangfu (Rice University) | Hinrichsen, Charles J. (Chevron) | Kan, Amy T. (Rice University) | Wang, Wei (Chevron) | Wei, Wei (Chevron) | Dai, Zhaoyi (Rice University) | Yan, Fei (Rice University) | Liu, Ya (Rice University) | Bhandari, Narayan (Rice University) | Zhang, Zhang (Rice University) | Ruan, Gedeng (Rice University) | Tomson, Mason B. (Rice University)
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 scaling-risk 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.
Yan, Fei (Rice University) | Zhang, Fangfu (Rice University) | Bhandari, Narayan (Rice University) | Ruan, Gedeng (Rice University) | Alsaiari, Hamad (Rice University) | Dai, Zhaoyi (Rice University) | Liu, Ya (Rice University) | Zhang, Zhang (Rice University) | Lu, Yi-Tsung (Rice University) | Deng, Guannan (Rice University) | Kan, Amy (Rice University) | Tomson, Mason (Rice University)
Turbulent flow in oilfield pipes is very common, especially around chokes, tubing joints, and safety values. However, the effect of turbulence on mineral scale precipitation has not been well understood. The objective of this study was to investigate mineral scale formation and inhibition under turbulent conditions.
A novel tubing testing method has been developed to enable the study of turbulence in a tubing apparatus. In the tubing apparatus that consists of a long tubing (200 to 500 ft) and a high flow pump, high-velocity turbulent flow was generated. In another tubing experiment, a valve was installed in the tubing to examine the impact of valves on mineral scale precipitation. Barite scale formation and inhibition by inhibitors were investigated in turbulent flows by these novel approaches.
In the experiment, barium concentrations in the effluent of the tubing were measured to determine whether barite precipitation occurred in the tubing. Critical saturation index (SI) was determined by a series of experiments for both laminar and turbulent flow. Experimental results show the effect of turbulence depends on several factors such as reactant ratio and scale inhibitor. Under our test conditions, when the molar ratio of sulfate to barium is around one, we observe no difference in barite precipitation kinetics between laminar and turbulent flow without scale inhibitor; however, in the presence of scale inhibitor, barite precipitation kinetics is slightly faster in turbulent flow, or critical SI is higher in laminar flow than that in turbulent flow. When the molar ratio of sulfate to barium is high, critical SI of laminar flow is always slightly higher than turbulent flow with and without inhibitor. Two different tubing materials, i.e. polyethylene and stainless tubing, were both investigated in this study and experimental results shows the effect of turbulence on barite precipitation kinetics is the same for both materials. In the tubing with valve experiment, the valve in the tubing did not show an influence on barite precipitation kinetics.
This paper presents a novel tubing apparatus to investigate the effect of turbulence on scale control in oilfield. The findings in this paper will advance our understanding in scale control especially under turbulent conditions, and aid in developing optimal doses of scale inhibitors with regard to flow regimes.
Zhang, Fangfu (Brine Chemistry Consortium, Rice University) | Dai, Zhaoyi (Brine Chemistry Consortium, Rice University) | Zhang, Zhang (Brine Chemistry Consortium, Rice University) | Al-Saiari, Hamad (Brine Chemistry Consortium, Rice University) | Yan, Fei (Brine Chemistry Consortium, Rice University) | Bhandari, Narayan (Brine Chemistry Consortium, Rice University) | Ruan, Gedeng (Brine Chemistry Consortium, Rice University) | Liu, Ya (Brine Chemistry Consortium, Rice University) | Lu, Yi-Tsung (Brine Chemistry Consortium, Rice University) | Deng, Guannan (Brine Chemistry Consortium, Rice University) | Kan, Amy T. (Brine Chemistry Consortium, Rice University) | Tomson, Mason B. (Brine Chemistry Consortium, Rice University)
Calcium carbonate is the most common scales in oilfield and thus has been heavily studied. However, calcium carbonate scale problems continue to occur in oilfield causing significant economic loss. To better control carbonate scale, reliable models on carbonate scaling risk and inhibition predictions are clearly necessary, which motivates this study.
To develop such a model, it is necessary to gain a better understanding on mineral nucleation and inhibition kinetics based on experimental studies, which can correctly interpret field data and observations on carbonate scale occurrence. While heavily studied, what has been commonly ignored or failed to obtain in previous studies is a strict control of pH and CO2 pressure as well as a precise calculation of carbonate supersaturation in brine. Unlike BaSO4 or CaSO4, pH and CO2 pressure can strongly affect the supersaturation of carbonate in brine. Therefore, without careful control of pH and CO2 pressure and precise calculation of carbonate supersaturation, the reliability of data on carbonate scaling and inhibition kinetics can be questionable. Also, the difficulty in obtaining such a reliable control and calculation has limited studies on carbonate nucleation and inhibition kinetics to low temperature from 77-200 °F.
In this study, we have developed robust procedures in controlling experimental pH and CO2 pressure and calculating carbonate supersaturation from 39-350 °F. With newly developed apparatus and protocol, we studied the precipitation and inhibition kinetics of calcium carbonate in the time range of seconds to more than 24 hours. The inhibition efficiency of 9 commonly used inhibitors including both phosphonates and polymers were characterized at different temperature and supersaturation levels. Experimental results were consistent and reproducible. Furthermore, a novel inhibition model has been developed based on data from this study. Finally, field observations on carbonate scaling kinetics of a number of wells are used to validate our new model and minimum inhibitor concentrations observed in the field are consistent with model predictions. In conclusion, this study provides reliable methods in studying carbonate scales and the newly developed models can provide accurate predictions of scaling risk and inhibition, which can help optimize the scale treatment plan.
Dai, Zhaoyi (Rice University) | Zhang, Fangfu (Rice University) | Yan, Fei (Rice University) | Bhandari, Narayan (Rice University) | Ruan, Gedeng (Rice University) | Zhang, Zhang (Rice University) | Liu, Ya (Rice University) | Alsaiari, Hamad A. (Rice University) | Lu, Yi-Tsung (Rice University) | Deng, Guannan (Rice University) | Kan, Amy T. (Rice University) | Tomson, Mason (Rice University)
Mineral scale formation can lead to the blockage and shutdown of production wells in the oil and gas industry. Large amounts of scale inhibitors are added to mitigate the losses due such mineral scale formation. Both insufficient and excessive scale inhibitor additions can cause unnecessary expenses. Because inhibition mechanisms are poorly understood, current models do not predict accurately the minimum effective dosage (MED) required for different inhibitors, temperatures, and inhibition times over wide ranges. Using a new approach, this paper developed a theoretical model to predict scale inhibition kinetics based on the classical nucleation theory and the regular solution theory. This model assumes that scale inhibitors can change the nucleus structure and the apparent saturation status of the scale minerals. These impacts were modeled to be proportional to the inhibitor concentrations. The model accurately predicted the precipitation and inhibition kinetics of barite and calcite with or without the presence of eight different scale inhibitors up to 90 and 175°C, respectively. This study can be used as a template to evaluate scale and inhibition kinetics, predict MED, and elucidate scale inhibition mechanisms on a common theoretical basis.
Ruan, Gedeng (Rice University) | Kan, Amy T. (Rice University) | Dai, Zhaoyi (Rice University) | Yan, Fei (Rice University) | Zhang, Fangfu (Rice University) | Bhandari, Narayan (Rice University) | Alsaiari, Hamad A. (Rice University) | Liu, Ya (Rice University) | Zhang, Zhang (Rice University) | Lu, Yi-Tsung (Rice University) | Deng, Guannan (Rice University) | Tomson, Mason B. (Rice University)
Halite (NaCl) scale is a non-conventional scale, which happens due to the temperature or pressure drop, or water evaporation at extremely high TDS environment (TDS up to 350,000 mg/L), such as deepwater field, shale formations, gas and gas condenstate fields. Compared to other conventional mineral scales, like barite or calcite, there is no standardized experimental procedure to screen and evaluate halite scale inhibitors. Because of the extremely high solubility of NaCl, it is very challenging but important to accurately control and calculate the halite saturation index (SI) or saturation ratio (SR) experimentally and theoretically. The Brine Chemistry Consortium has been continuously working on the development and optimization of the thermodynamic model, ScaleSoftPitzer (SSP), for the the prediction of the solubility and scaling risks of various minerals in mixed electrolytes over a wide range of temperature and pressure based on Pitzer theory. Recently the new SSP2017 version which can predict the halite SI within SI error of 0.01 from 25 to 90 °C with up to 1.0 m Ca2+ (~35,000 mg/L). In this study, two static bottle testing methods have been developed by taking the advantage of the powerful calculation ability of SSP2017 to fast and accurately screen and evaluate the inhibition efficiency of different chemicals. The Method One is a temperature-driven and monitoring method and the Method Two is a brine-mixing method of mixing a naturally saturated NaCl solution, a highly concentrated chloride salt solution and an inhibitor solution. By using these two novel methods, over 40 different chemicals are screened and evaluated, including small molecules and polymers in the category of polyacrylate, polyaspartate, polysulfonate, carboxylate sulfonate copolymer, phosphonate polymer, etc. From the experimental results, five carboxylate sulfonate copolymers (Inh #H14, #H23, #H26, #H30, #H40) have better inhibition efficiency. The synergistic effect of Inh #H40 and Fe(CN)64– is also investigated, and 130 mg/L of Inh #H40 and 20 mg/L of Fe(CN)64– can effectively inhibit the halite scale at simulated field condition of SI = 0.09 (SR = 1.23, TDS ~ 353,800 mg/L) and 0.6 m Ca2+ at 70 °C. In summary, two fast and accurate methods have been developed for the screening and evaluation of halite scale inhibitors, and with the usage of effective halite scale inhibitors, the costs of halite scale control can be significantly reduced both in freshwater usage for dilution and high-salinity produced water treatment.