Article pubs.acs.org/EF
Cite This: Energy Fuels XXXX, XXX, XXX−XXX
Influence of Adding Asphaltenes and Gas Condensate on CO2 Hydrate Formation in Water−CO2−Oil Systems Gustavo A. B. Sandoval,*,† Roney L. Thompson,*,† Cristina M. S. Sad,‡ Adriana Teixeira,§ and Edson J. Soares*,∥
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COPPE, Department of Mechanical Engineering, Centro de Tecnologia, Universidade Federal do Rio de Janeiro, Ilha do Fundão, 21945-970 Rio de Janeiro, RJ, Brazil ‡ Laboratory of Research and Development of Methodologies for Analysis of Oils (LabPetro), Chemistry Department, and ∥ LABREO, Department of Mechanical Engineering, Universidade Federal do Espírito Santo, Avenida Fernando Ferrari, 514, Goiabeiras, 29075-910 Vitória, Espírito Santo, Brazil § CENPES, Petrobras, 21945-970 Rio de Janeiro, RJ, Brazil ABSTRACT: Gas hydrate formation is a huge flow assurance problem in offshore production of oil and gas. However, there have been some reported cases in oil-dominated systems where the hydrates do not form, even though the high-pressure and low-temperature environments induce favorable thermodynamic conditions. The reason for this unexpected result seems to be related to the presence of natural chemical compounds in crude oils that prevent the hydrates’ nucleation and agglomeration. Because the number of works in this specific topic are scarce, in the present work, we study the role played by saturates (hydrocarbon compounds) and asphaltenes (heterocyclic compounds), which are commonly present in crude oil, on hydrates that are formed from CO2 molecules in water−CO2−oil systems. Our tests were carried out in an assembly composed of a rotational rheometer with a magnetic pressure cell, which was connected to a high-pressure system. Our main results are displayed in terms of viscosity as a function of time at constant shear rate, pressure, and temperature. In this kind of experiment, hydrate formation is associated with a jump of viscosity. Our data suggest that asphaltenes retard the CO2 hydrate nucleation and formation in the crude oils studied in this work.
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INTRODUCTION Natural gas hydrates are solid compounds that are formed when water hydrogen bonds (hosts) encage and hold one or more types of guest molecules (usually low-molecular-weight gases) at particular thermodynamic conditions of high-pressure and low-temperature.1 The arrangement of the host−guest molecules forms a cage-like structure in different points of the system, which is surrounded by a thin layer of liquid water that leads to a capillary bridge between hydrate particles because the hydrate surface is hydrophilica.3 The attraction among the formed cages allows their accumulation which builds a lattice. This increases until a crystalline structure has formed, physically resembling ice. Three types of hydrate structures are most commonly found in the environment: sI, sII, and sH. The kind of stabilized structure depends on the nature and geometry of the guest molecule,1 as well as the pressure and temperature conditions of its formation.4 Structure I is the most common in natural environments. A single guest molecule of a pure gas, such as methane, ethane, and carbon dioxide, composes its crystal. Structure II is less common. It occurs in the presence of a mixture of gases, such as natural gas, but a single molecule also composes its crystal. Finally, in structure H, which is the scarcest in nature, the cages have, at least, two different guest molecules, such as a molecule of methane (the smallest molecule) and a molecule of dimethylbutane (the largest molecule). The vast majority of hydrates are found in permafrost regions or in deep and ultradeep water because the necessary conditions for their formation (free water, guest molecule, high © XXXX American Chemical Society
pressure, and low temperature) are all satisfied in these environments.5 It is estimated that the quantity of hydrates widespread in the earth is, at least, twice as large as the other fossil fuels,6 which turn these compounds into a huge potential natural resource. Some of the limitations and challenges with respect to natural gas hydrates’ exploitation have been discussed in some recent reviews, such as refs.7,8 An idea to produce natural gas from hydrates reservoirs has been proposed in ref 9. Some interesting investigations on the subject have been realized in refs.10−12 Another application of hydrates is in the refrigeration industry, as CO2 hydrates can be used to improve the efficiency of secondary refrigeration loops, aiming to reduce the amount of conventional refrigerants.13−15 However, the main interest in understanding the mechanism of hydrate formation is their harmful role in offshore oil and gas production, because hydrate formation within a pipeline can totally block the fluid transport. During the offshore production process, hydrates generally appear in gas lines but they can also arise in oil line production. The fluid extracted has many components with a high content of methane gas and, in some cases, a high amount of carbon dioxide, as in the Brazilian pre-salt oil wells or in South-East Asia. In the latter, the CO2 content is higher than 0.7 mole fraction.16 Given the scale of the problem produced by hydrate formation in the oil and gas industry, flow assurance demands Received: April 18, 2019 Revised: July 3, 2019 Published: July 5, 2019 A
DOI: 10.1021/acs.energyfuels.9b01222 Energy Fuels XXXX, XXX, XXX−XXX
Article
Energy & Fuels
this complexity is highly dependent on the oil composition. In fact, how the crude oil components affect hydrate formation and inhibition it is still not well-understood, in the industry or in academia. From the practical point of view, it would be valuable to know from the chemical composition which kind of oil would provide a higher tendency to the appearance and agglomeration of hydrates when subjected to the same thermodynamic conditions. Palermo et al.26 reported that the oil extracted from a Brazilian oil well, called Campos Basin, has some natural surfactants, which may explain why no hydrate plugging occurs in these flow lines, even during shutdown and restart processes. It is known that the main differences between the crude oils are their relative amount of different kinds of hydrocarbons, as saturates, aromatics, resins, and asphaltenes, for example. In fact, from the chemical and the rheological points of view, what is important is the molecular relationship between the numbers of constituents. Undoubtedly, for hydrate formation, one of the most important petroleum constituents is the group of asphaltenes. These oil constituents have gained importance in the recent years because of the increasing demand of heavy oil extraction. Asphaltenes are generally defined as insoluble in normal alkanes (e.g., npentane or in n-heptane) but soluble in aromatics (e.g., toluene). They are the most polarizable component of the oil and their relative amount depends on the source of the crude oil. Asphaltenes are important stabilizers of water-in-oil emulsions;27 they are natural interface-active components that reduce the surface tension and inhibit drops’ coalescence.28,29 In the present work, we investigate the influence of the crude oil properties on hydrate formation. Consequently, we used gas condensate (GC) and asphaltenes to study the effect of the type of compound employed.
the adoption of some strategies to mitigate that process. A common procedure is to introduce chemical hydrate inhibitors to control or avoid hydrate formation. Hydrate inhibitors are divided into two main groups: thermodynamic inhibitors (TIs) and low-dosage hydrate inhibitors (LDHIs). TIs such as alcohols, glycols, and saline solutions act by changing the hydrate equilibrium curve. In this case, for a certain pressure level, the corresponding equilibrium temperature of hydrate formation is reduced, shifting the chemical potential of water. In field operations, the use of TIs are becoming less frequent because of a number of well-known disadvantages, such as: (1) the large amount of TIs required for the process to be effective, achieving in some cases quantities between 20 and 50 wt % or more;17 (2) environmental damage (some companies prefer the use of ethanol or glycols instead of methanol); and (3) the reduction in performance downstream of the injection point because of evaporation. With respect to LDHIs, they are divided into two classes: kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs). KHIs affect the kinetics of the process, increasing the induction time and, therefore, retarding the crystal growth, which allows the accessible transport of the forming hydrate fluid for a larger period of time. The mechanism of inhibition of the AAs is quite different. This kind of inhibitor has no effect on the formation of the hydrate crystal, but acts to avoid their aggregation. The formed hydrate particles are transported by the flow. In this case, the solution behaves as a low-viscous liquid, even at high subcooling conditions. To provide an explanation for the underlying mechanism of this process, Song et al.18 argue that AAs reduce the water−oil interfacial tension and, consequently, the capillary forces are reduced, thus avoiding hydrate aggregation. However, at higher water-cut (>50%), it is very difficult to avoid hydrate agglomeration, even with the addition of AAs. In this high water-cut, once hydrate crystals appear, the formation of driving forces strongly overcomes the hydrodynamic forces (breaking forces), facilitating the free water to be converted into hydrate. Several equipment and setup configurations have been used to study the mechanism of hydrate formation, as well as the efficiency of inhibitors of the kinds discussed earlier. At laboratory scales, there are mainly two experimental methods to analyze hydrate formation: at atmospheric pressure or using high-pressure systems. The atmospheric pressure method is possible using, for example, cyclopentane (CP)19−23 and tetrahydrofuran (THF).24,25 In these cases, the hydrate structure that is formed is the same as the one formed with natural gas.19,24 It is worth noting that CP is immiscible and THF is miscible in water. Hence, if we are interested in mimicking oil−water systems, the first one is by far more convenient. In the second strategy, the pressure level is close to those found in the oil production field and we are able to analyze hydrate formation in more real thermodynamic conditions. This latter strategy is the one used in the present work. Despite the number of related studies and development of many different preventive methods, gas hydrates’ formation still continues to be a flow assurance problem with a high economic impact, which is not surprising. In addition to the complex mechanism of nucleation and growth (hydrate kinetics), the mixture of gas hydrate and oil is an extremely complex non-Newtonian material, which exhibits many kinds of non-Newtonian behavior, such as shear-thinning, viscoelastic and viscoplastic effects, and time dependency. Clearly,
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EXPERIMENTAL APPARATUS AND PROCEDURE
Oils and Condensate Used. We used two different oils in our experiments, called here (A) and (C). The first is a heavy oil extracted from the post-salt wells. The oil (C) is the same used in our previous work.30 This oil comes from the pre-salt layer, and is classified as a medium oil. We also use a third material, a GC. All samples of oils (A) and (C), and the GC are offshore hydrocarbons from the Brazilian ́ coast (precisely from the state of Espirito Santo) and were provided by Petrobras. The GC was mixed with the heavy crude oil (A) to increase the amount of saturates in the oil. The physicochemical properties of each of our materials are shown in Table 1. The characterization of each oil and GC displayed in Table 1 was carried out according to specific procedures established by ASTM and ISO. During the oil treatment process, the free water (nonemulsified water) was first separated from the crude oil. The water content analysis (ASTM D4377, 2011) was determined in the water-in-oil emulsions according to ASTM D4377,31 using a Metrohm KF titrator (model 836 Titrando) equipped with a double-platinum electrode. Oils that presented water content in excess of 2% (v/v) were dehydrated by using 200 mL of a concentrated commercial demulsifier (composed of surfactants, containing isoprene and glycol propylene oligomer species) at 60 °C and centrifuged at 1600 rpm for 15 min.32−34 After the demulsification, the water content was determined again to verify if it was below 0.5% (v/v). These oils were called “dehydrated oil”. The density was determined in compliance with ISO 12185-9635 (International Organization for Standardization, 1996) by injecting the sample into the digital automatic analyzer Stabinger SVM 3000 (Anton Paar). API gravity was also reported in compliance with ASTM D125036 and ISO 12185.35 Total acid number measurements followed the ASTM D66437 by potentiometric titration (Metrohm 836 automatic titrator) of the sample with an alcoholic solution of potassium hydroxide. The B
DOI: 10.1021/acs.energyfuels.9b01222 Energy Fuels XXXX, XXX, XXX−XXX
Article
Energy & Fuels Table 1. Properties of the Dehydrated Oils and Condensate Gas properties
oil A
water content (% v/v) density at 20 °C (g cm−3) API gravity at 15.56 °C TAN (mg of KOH g−1) SARA content saturates (wt %)
0.42 (0.01) 0.931 (0.003) 19.9°
