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.
Zhang, Nan (Statoil) | Schmidt, Darren (Statoil) | Choi, Wanjoo (Statoil) | Sundararajan, Desikan (Statoil) | Reisenauer, Zach (Statoil) | Freeman, Jack (Statoil) | Kristensen, Eivind Lie (Statoil) | Dai, Zhaoyi (Rice University) | Kan, Amy (Rice University) | Tomson, Mason (Rice University)
Produced water from the Bakken and Three Forks formations in the Williston Basin is notably high in total dissolved solids, which leads to many well maintenance issues related to halite scaling (salt precipitation). Fresh water is widely used to prevent halite scaling; however, initial treatment programs tend to "overtreat" the problem and leads to high operation and maintenance costs. An effort to improve halite scale management has been explored, which includes identification of wells that need fresh water injection; optimization of the fresh water volumes; minimizing deferred oil production; and preventing other scales associated with the presence of fresh water in the wellbore. Several methodologies have been applied to characterize halite scaling and achieve optimization of fresh water treatments. A scaling prediction model was developed and validated with literature data and field data. The model calculates saturation ratios and optimal fresh water volume, which provides critical inputs for treatment recommendations. Field tests have been conducted to dynamically characterize produced fluids. Results have influenced new methods for treatment and fresh water injection techniques. Halite scale inhibitors have also been examined in laboratory and field tests. This work resulted in optimizing both fresh water and chemical treatment programs to minimize halite scaling. Significant cost savings have been achieved from reduced fresh water usage, thereby lowered produced water disposal.
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.
Yan, Fei (Rice University) | Bhandari, Narayan (Rice University) | Zhang, Fangfu (Rice University) | Ruan, Gedeng (Rice University) | Dai, Zhaoyi (Rice University) | Liu, Ya (Rice University) | Zhang, Zhang (Rice University) | Alsaiari, Hamad (Rice University) | Kan, Amy (Rice University) | Tomson, Mason (Rice University)
Static jar test and dynamic loop are two major test methods used for study of mineral scale formation and evaluation of scale inhibitors. In both methods, the flow is generally in the regime of laminar condition, which may not be representative of turbulent flow under field conditions. Turbulent flow in oilfield pipes is very common, especially around chokes, tubing joints, and safety values. The objective of this study is to investigate mineral scale formation and control under turbulent conditions.
A novel testing method of rotating cylinder apparatus has been developed for turbulent conditions. In rotating cylinder experiments, highly turbulent flow (up to a Reynolds number of 11,000) was created by a rotating cylinder under field temperature of 70 °C. Barite scale formation and inhibition by several typical inhibitors were investigated under different flow conditions.
During the experiments, barium concentration was measured periodically to determine scale kinetics. Barite precipitate was collected at the end of the experiment and examined by scanning electron microscope (SEM). Experimental results show no significant difference in precipitation kinetics between laminar and turbulent flow without scale inhibitors. However in the presence of scale inhibitors, precipitation kinetics was slower under high turbulence. SEM images also display major difference in barite size and morphology between different flow conditions. Highly crystalline barite with an average size of 10 µm was found in laminar flow, whereas amorphous or poorly crystalline barite of only sub micrometers was formed in turbulent flow. These results indicate that scale inhibitors may be more effective under some turbulent conditions, as opposed to previous observations.
The insights presented in this work will help to understand scale control in oilfield pipes especially under turbulent conditions, and develop optimal doses of scale inhibitors with regard to flow regimes.
Zhang, Zhang (Rice University) | Liu, Ya (Rice University) | Dai, Zhaoyi (Rice University) | Bhandari, Narayan (Rice University) | Zhang, Fangfu (Rice University) | Yan, Fei (Rice University) | Ruan, Gordon (Rice University) | Alsaiari, Hamad (Rice University) | Lu, Yi-Tsung (Rice University) | Deng, Guannan (Rice University) | Kan, Amy (Rice University) | Tomson, Mason (Rice University)
Little research has been done to understand how chelating agents might reverse the effect of Fe(III)/Fe(II) on scale inhibitors in oilfield conditions. Iron ions are common cations existing in oil and gas production water. Most Fe(II) ions come from dissolution of siderite in reservoir and corrosion of steel pipes. Fe(III) in solution, can be formed by Fe(II) reduction of H2O, dissolution of magnetite or other Fe(III) containing minerals or when produced water is exposed to air. Both Fe(II) and Fe(III) can cause severe problems in production. Fe(II) can form FeS and FeCO3 scale. Fe(III) can precipitate as ferric hydroxide or with Fe(II) as magnitite particles and cause damage to formation permeability. Moreover, both Fe(II) and Fe(III) have significant detrimental effects on common scale inhibitors. One of the most popular methods for iron control is the application of chelating agents, such as EDTA, NTA or citric acid, to chelate Fe(II)/Fe(III)to prevent such detrimental effects.
In this work it is shown that Fe(II) and Fe(III) can significantly impair performance of common scale inhibitors such as DTPMP, PPCA and PVS. The inhibition time of DTPMP for barite can drop more than 90% in the presence of 1 mg/L Fe(II) or Fe(III)at 70°C. In this research, a mechanistic study has been done to deduce whether EDTA and citric acid can reverse the loss of scale inhibitor performance by Fe(II)/Fe(III). We find that Fe(III) impairs scale inhibitor performance by forming iron hydroxide particles which can adsorb scale inhibitors from solution. Both EDTA and citric acid are found to be able to eliminate the negative impact of Fe(III) on scale inhibitors, but through different mechanisms. EDTA works by direct chelation of Fe(III) in solution, before a solid phase is formed; while citric acid works by competitive adsorption with scale inhibitor onto ferric hydroxide particle surfaces. The impact of EDTA and citrate on reversing Fe(II) effect on scale inhibition is also discussed.
Yan, Fei (Rice University) | Zhang, Fangfu (Rice University) | Bhandari, Narayan (Rice University) | Liu, Ya (Rice University) | Wang, Lu (Rice University) | Dai, Zhaoyi (Rice University) | Zhang, Zhang (Rice University) | Bolanos, Valerie (Rice University) | Kan, Amy (Rice University) | Tomson, Mason (Rice University)
The reactions between scale inhibitors and formation minerals determine the inhibitor retention and release after inhibitor squeeze treatment and hydraulic fracturing. Scale inhibitor is an important ingredient in fracturing fluids to prevent mineral scale depositions during fracturing, shut-in and flowback stages. The interaction of scale inhibitors between carbonate formation is well understood but the interaction of scale inhibitors between shale and sandstone formation has not been investigated thoroughly. The primary objective of this study is to develop mechanistic understanding of interactions between scale inhibitors and shale and sandstone minerals.
In this study, adsorption and precipitation of a phosphonate scale inhibitor – DTPMP on shale minerals were investigated at 70°C. Equilibrium adsorption isotherms were determined for various inhibitor concentrations at different pH values. At low phosphonate concentration, the interaction between inhibitors and shale can be characterized as surface adsorption; at high phosphonate concentrations, inhibitors precipitate with cations released from shale minerals. The interaction of scale inhibitor and sandstone formation was evaluated in coreflooding experiments by repeated squeeze and acid treatment. The inhibitor return of an identical second DTPMP squeeze showed almost the same return curve as the first squeeze. An acidizing pretreatment demonstrated improvements in squeeze performance. It is proposed that acid treatment dissolves soluble minerals such as calcite, and DTPMP inhibitors forms less soluble precipitate such as iron phosphonate in the formation, which results in the enhancement of squeeze. The dissolution rate constant of DTPMP precipitate was determined at three different temperatures and the established relationship can be used to predict rate constant under other temperature conditions.
The insights presented in this work will help to understand the fate of phosphonate scale inhibitor in shale and sandstone reservoirs, manage the use of scale inhibitor in fracturing fluids, and design optimum scale squeeze packages for scale control in oil field.
Wang, Qiliang ‘Luke’ (Department of Civil and Environmenal Engineering, Rice University) | Zhang, Zhang (Department of Civil and Environmenal Engineering, Rice University) | Kan, Amy (Department of Civil and Environmenal Engineering, Rice University) | Tomson, Mason (Department of Civil and Environmenal Engineering, Rice University)
Ferrous sulfide (FeS) precipitation is a severe problem and the significance of this problem is increased in the shale gas and oil production due to the potentially increasing biologically and thermally induced sulfide production. Although FeS scale is ubiquitous, little is understood about its precipitation and inhibition properties due to experimental difficulties. In conventional research, we used a batch reactor to study the precipitation kinetics and inhibition of FeS formation. In order to assess scaling risk in pipes, a new plug flow reactor was developed under anoxic condition at different ionic strength (IS), pH and temperature to enable more reliable study of FeS precipitation kinetics at high surface to solution ratio. The precipitation kinetics of FeS is successfully fitted by a second/pseudo-first order rate equations for batch/plug flow systems. The rate of precipitation increases with increasing pH and temperature, and decreases with increasing IS. Commercial scale inhibitors, citrate, EDTA and other chelating agents have been tested for their inhibition effects on FeS precipitation. The new plug flow apparatus not only adds reliable data to the limited database of scaling kinetics in realistic flowing pipes, but also supplies a new method to study the effect of inhibitors in oil production systems. The research outcomes will contribute to the prediction of FeS scaling risk under different brine composition and well conditions.
Sulfonated polymers are used in the oil field for scale inhibition. In this study, Al-sulfonated polycarboxylic acid (Al-SPCA) hybrid nanoparticles (NPs) were prepared by taking an environmentally friendly approach. The particle size of these materials was controlled at approximately 80 nm by applying hydrothermal synthetic methods with urea as a slow-neutralization agent. Reaction parameters (e.g., concentration of salt solution, reaction time, urea concentration, and ionic strength) were investigated to optimize NP synthesis. The mobility of Al-SPCA hybrid NPs decreases dramatically in a 1% (wt/wt) KCl solution. With phosphinopolycarboxylic acid (PPCA) as a dispersant, NPs were wellsuspended in a 1% KCl solution. Absorption of PPCA by hybrid NPs increases their negative surface charge and decreases particle deposition. The retention and flowback performance of hybrid NPs was compared with the neat-chemical-squeeze simulation in ground-core-column experiments. The results show that the slow release of sulfonated polymer from solid hybrid NPs in a porous medium may have potential inhibitor-treatment application in the oil field.
A novel barite-inhibition assay based on the nucleation and inhibition model has been proposed and used to evaluate the thermal stability of phosphonates and polymeric scale inhibitors with regard to their potential application in high temperature wells. Systematic experiments have been conducted to investigate the time (minutes to days) and temperature (up to 200°C) dependence of inhibitor thermal degradation, the impact of stainless steel and iron on the degradation of inhibitors at high temperatures, and the difference between aging tests with inhibitors in solution and with those inhibitors adsorbed on core materials. The results not only enable a more accurate understanding of the thermal degradation of scale inhibitors but also facilitate the selection and placement of scale inhibitors for high-temperature oil and gas production.
As the oil and gas industry is making firm stride in deepwater exploration and development, possible thermal degradation of scale inhibitor molecules poses a great challenge for scaling control and flow assurance for high temperature reservoirs. Although extensive research has been conducted to test thermal stability of scale inhibitors, little work has been devoted to study the thermodynamics/kinetics of thermal degradation of scale inhibitors. In this work a novel and efficient testing approach based on inhibition kinetics has been developed and successfully applied to determine the fraction of the initial inhibitor molecules in preheated samples of scale inhibitors with various generic chemistries. Moreover, for the first time, we have modeled the kinetics of inhibitor thermal degradation based on the integrated first-order rate equation and Arrhenius equation, with good agreements between the model predictions and experimental data. The preheated scale inhibitors have been analyzed by nuclear magnetic resonance (NMR) spectroscopy for organic compound characterization. Our results and predictions based on inhibition testing assay are consistent with the 31P/1H NMR analyses. This work has enabled an in-depth understanding of the time and temperature dependence of thermal degradation of scale inhibitors, and facilitates the rational selection and deployment of scale inhibitors for high temperature oil and gas production.