Article pubs.acs.org/jced
Antiagglomerant Hydrate Inhibitors: The Link between HydratePhilic Surfactant Behavior and Inhibition Performance Sahana K. Nagappayya,† Rebecca M. Lucente-Schultz,*,† V. Mark Nace,‡ and Vickie M. Ho† †
Nalco Champion, an Ecolab Company, 7705A Highway 90A, Sugar Land, Texas 77478, United States Nalco Champion, an Ecolab Company, 3130 FM 521, Fresno, Texas 77545, United States
‡
S Supporting Information *
ABSTRACT: The application of antiagglomerant hydrate inhibitors (AAs) is becoming more important as advancing technology allows access to petroleum reserves with extreme conditions including high pressures, high temperatures, sour reservoirs, and arctic climates. Application of thermodynamic hydrate inhibitors (THIs) is becoming cumbersome and outdated due to high volumes required, especially in offshore applications. High subcooling scenarios and capital costs preclude the use of kinetic hydrate inhibitors (KHIs) and THIs. Even though AAs are industrially recognized surfactants, they have not been extensively studied with regard to their surfactant properties as related to performance. In this paper, selected AAs have been examined in terms of their surfactant properties. These findings were then related to hydrate inhibition performance in a crude oil system. It is widely known that AAs perform better with increased salinities and decreased water-cuts. This study provides data that shines light on the plausible reasons for these observations.
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INTRODUCTION With the growing demand for energy on a global scale, increased exploration and production is being carried out in difficult terrains and challenging conditions. With these, challenges in the production and transportation of petroleum fluids have increased. One of the biggest obstacles faced today in flow assurance is the prevention and mitigation of gas hydrates. These are solid cage-like clathrate structures containing water and stabilized by small incorporated gas molecules like methane. Hydrates can pose serious problems and can lead to plugging that causes production loss and potential safety hazards to operators.1,8 Prevention of gas hydrates can be accomplished via physical methods such as raising the temperature, insulating pipes/ flowlines, and lowering the pressure;1,2 however, these methods are generally not used as mitigation strategies, as they can be prohibitively expensive and are sometimes not even possible. In recent times, the use of chemical hydrate inhibitors has become the preferred solution for hydrate mitigation. These inhibitors are classified under two categories: thermodynamic hydrate inhibitors (THIs) and low dosage hydrate inhibitors (LDHIs). THIs are typically solvents like methanol or ethylene glycol that are added in amounts proportional to the produced water to keep the formation of hydrates from occurring.4−6 But since these THIs are added in large quantities (mass fraction of 0.20 to 1 based on water-cut), they can be cost-prohibitive and also adversely affect oil quality, a problem which must then be dealt with downstream. Currently there is great interest in developing LDHIs, which are typically dosed in much smaller quantities than THIs (mass fraction of 0.01 to 0.05 based on © 2014 American Chemical Society
water-cut). There are two types of LDHIs: water-soluble polymers called kinetic hydrate inhibitors (KHIs) and antiagglomerant hydrate inhibitors (AAs), which are typically surfactants. KHIs delay the hydrate nucleation process for a certain length of time, thereby providing enough time to transport fluids before hydrates are formed. AAs, on the other hand, allow hydrates to form as a transportable slurry and prevent them from agglomerating to form physically larger hydrate structures that can block flowlines. Typical structural motifs of AAs are a polar, hydrate-philic head and a hydrophobic, fatty chain. Due to the surfactant nature of the molecules, they will accumulate at the water/oil interface, where hydrates first begin to form.1,7 From there, the hydratephilic headgroup attaches to the hydrate crystal surface, anchoring the inhibitor into place. The fatty chain both prohibits further hydrate growth and facilitates dispersion of the hydrate crystals into the liquid hydrocarbon phase, rendering mobility to the already formed hydrates.1 In 2011, Zerpa et al. published a detailed review of the surface chemistry and interfacial phenomena existing between LDHIs and gas hydrates.3 In this work we studied and compared the surfactant behavior of two AAs, Chemicals A and B, and connected it to the performance of the chemicals as AAs. Special Issue: In Honor of E. Dendy Sloan on the Occasion of His 70th Birthday Received: July 1, 2014 Accepted: September 30, 2014 Published: October 8, 2014 351
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Although A and B have similar molecular characteristics, their phase behavior and antiagglomerant performance were quite different in a crude oil system with varying aqueous salinity. The physical appearance of the crude oil/brine mixtures and relative partitioning of A and B were used to rationalize the antiagglomerant performance outcomes.
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EXPERIMENTAL METHODS Materials. The antiagglomerants A and B used in this study are quaternary ammonium salts and are proprietary molecules; their structures are not depicted in this paper. The crude oil used for the study is representative of typical Gulf of Mexico oil. Studies with other oil systems have also been carried out and may be published at a later date. The SARA (saturates, aromatics, resins, asphaltene) analysis is a common technique used to describe the composition of a crude oil, and those results are listed in Table 1. The brine used in the salinity scans and performance tests was made using sodium chloride purchased from Sigma-Aldrich and distilled water. Table 1. SARA (Saturates, Aromatics, Resins, Asphaltenes) Analysis of the Crude Oil Used for the Studies (In Mass Fraction) S
A
R
A
0.445
0.348
0.159
0.469
Hydrate Inhibitor Test Procedure. Constant pressure AA testing was performed utilizing a rocking cell apparatus. The rocking cell apparatus has 10 high-visibility sapphire cells that can withstand pressures of up to 34.4 MPa. Each cell contains a steel ball for agitation and mixing. These cells are mounted on a rack that rocks up and down at a rate of one time per minute. The rocking cell apparatus is shown in Figure 1. For the test, each cell was filled with 5 mL of crude oil and 5 mL of brine. The AAs were dosed based on the water volume in the cells. The cells were flushed with synthetic gas to displace any residual ambient gas and then pressurized to 17.2 MPa at 21 °C. The composition of the synthetic gas is given in Table 2. The cells were allowed to equilibrate for an hour with rocking and then cooled linearly to 4 °C over a 3 h period of time with rocking. The cells were then rocked for an additional 6 h followed by a shut-in period, simulated by stopping the cells at the horizontal position, for another 6 h. Each test was restarted with rocking for 1 h, and the AA performance in each cell was evaluated throughout that time frame. Salinity Scans. 450 μL of each AA was dosed into a mixture of 5 mL of oil and 5 mL of brine to yield a dose of 0.039 mass fraction (based on the brine phase) in 15 mL flat-bottomed culture tubes purchased from Fisher Scientific. The concentration of salt in the aqueous solution varied from 0 to 1.70 mol·kg−1 of sodium chloride. Two sets of data were generated, one for each chemical, A and B. This mixture of oil, water, and chemical was thoroughly mixed and then left undisturbed. Photos were taken 2 min after mixing at room temperature and at 2 days post-mixing at 4 °C. The various phases were observed and their appearance noted. LC/MS Analysis of AA in Oil and Brine Phases. Using a pipet, aliquots of the oil and water layer were removed and analyzed for the presence of the AA using LC-MS. For LC-MS, a 2000 mL·L−1 stock solution of the chemical was prepared. This stock solution was diluted with isopropanol to yield solutions of varying dilutions from 1400 mg·L−1 to 2 mg·L−1.
Figure 1. Rocking cell apparatus for hydrate testing (top). Sapphire cells depicting pass and fail (middle and bottom, respectively).
Table 2. Composition of Synthetic Gas Used for Hydrate Performance Tests component
mole fraction
nitrogen methane ethane propane iso-butane n-butane iso-pentane n-pentane
0.0039 0.8726 0.0757 0.0310 0.0490 0.0079 0.0020 0.0020
These samples were transferred to centrifuge tubes and centrifuged for 30 s. The standard 2000 mg·L−1 solution was used to calibrate the mass spectrometer. The samples were injected into a Waters Xterra MC C8 column at 35 °C, at a flow rate of 500 μL·min−1 with an injection volume of 1 μL to 10 μL for 50 min. The mobile phase used was 0.25 molar ammonium 352
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acetate in acetonitrile. Additional details of this procedure are provided in the Supporting Information.
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RESULTS Hydrate Performance. Minimum passing dosages for the two hydrate inhibitors in crude oil were determined at low and high brine concentrations of (0.34 to 1.70) mol·kg−1 sodium chloride. The performance data are listed in Table 3. From the Table 3. Performance Data for Chemicals A and B in Crude Oila chemical
MED1b
MED2b
A B
0.0049 >0.029 (fail)
0.0025 0.0049
a
MED = minimum effective dose (in mass fraction). MED1 = MED in 0.34 m (2 %) sodium chloride; MED2 = MED in 1.70 m (10 %) sodium chloride. 0.0049 mass fraction = 1.0 vol. % AA; 0.0025 mass fraction = 0.5 vol. % AA; 0.029 mass fraction = 6.0 vol. % AA. bThe standard uncertainty for MED is ± 0.0012 mass fraction (= 0.25 vol.% AA).
table, it is evident that both chemicals are capable of mitigating hydrates under high salinity conditions, as expected. At lower brine concentrations, Chemical B was unable to inhibit the formation of hydrate deposits. Chemical A, however, did prevent hydrate deposition and agglomeration at low brine concentration. Salinity Scans. We speculate that the differences in the hydrate performance results of Chemicals A and B may be attributed to their relative solubility and resulting phase behavior in oil and aqueous phases. In this context, we roughly define “phase behavior” in terms of how the AAs emulsify crude oil and brine and also how they partition between the oil and water phases. The salinity scans of the chemicals were performed at atmospheric pressure, whereas the hydrate performance tests were conducted at elevated pressures of 14.4 MPa. Despite the pressure difference, however, we were able to correlate the results from the two types of experiments, as explained further. Photos depicting the oil and water phase distribution at different brine concentrations for Chemicals A and B appear in Figures 2 and 3, respectively. The top picture in both figures shows results for 2 min after mixing at room temperature, while the bottom picture in both figures shows results after aging for 2 days at 4 °C. From these, it is immediately apparent that the phase behavior of the AA/brine/oil systems is markedly different for Chemicals A and B. Focusing first on Chemical A, its presence in oil and brine produces reasonably stable emulsions after 2 min at room temperature throughout most of the salinity range tested (Figure 2, top). Emulsions were less stable in concentrations ranging from (0 to 0.68) mol·kg−1 sodium chloride after aging for 2 days at 4 °C (Figure 2, bottom). The salt concentration is known to have an effect on the relative partitioning of ionic surfactants in oil and water phases.2 It is also known that increasing the salt concentration can lead to increased oil solubility of ionic surfactants and the formation of water-in-oil emulsions.9 Surfactants that first form water-in-oil emulsions can facilitate antiagglomerate activity by predispersing the hydrate-forming water droplets;10 however, all surfactants that form water-in-oil emulsions are not good AAs, and not all AAs form emulsions.11
Figure 2. Oil and brine distribution with Chemical A after 2 min of mixing at room temperature (top) and after 2 days at 4 °C (bottom). Salinity conversions: 0 % = 0 m, 1 % = 0.17 m, 2 % = 0.34 m, 3 % = 0.51 m, 4 % = 0.68 m, 5 % = 0.86 m, 6 % = 1.03 m, 7 % = 1.20 m, 8 % = 1.37 m, 9 % = 1.54 m, 10 % = 1.71 m.
The sustained performance of Chemical A at high and low brine concentrations can be explained on the basis of its distribution between the oil and aqueous phases. At low brine concentration, LC-MS analysis shows that there is very little chemical in the water phase, as seen in Table 4. This is also evident visually in Figure 2 (bottom) where, relative to the original water level (red dotted line), the level of the water phase slowly decreases from (0.34 to 0.68) mol·kg−1 sodium chloride, indicating that the chemical is not appreciably entering and adding into the water phase. Prior to 0.34 mol· kg−1 sodium chloride, the level of water phase is slightly higher, and when no sodium chloride is added, the water phase is clouded presumably by the AA. It is not shown here, but we did test Chemical A in a zero salinity system and saw no AA performance. At concentrations higher than 0.68 mol·kg−1 sodium chloride, the water phase has given way to an oil-inwater emulsion. In fact, Table 4 shows that at both (0.34 and 1.70) mol·kg−1 sodium chloride, the vast majority of chemical was found in the oil or emulsion phase and very little in the aqueous phase. It is assumed that this trend is continuous between these two data points. We speculate that Chemical A maintains good performance throughout this salinity range, because it is present more in the oil and emulsion layer and has not partitioned very much into the aqueous layer. For a 353
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Table 5. LC-MS Data for Chemical B in Oil and Water Phases after 4 d of Partitioning at 4 °Ca m/mol·kg−1
Wb/ppm
Ob/ppm
Ec/ppm
0.34 1.70
48500 1527
2164 3092
31936 77977
a
m = molality of brine solution; W = amount of chemical in the water layer; O = amount of chemical in the oil layer; E = emulsion loss. bOne sample was analyzed 10 times, giving a relative standard deviation (% RSD) of 6.7 %. cCalculated data.
much less chemical available in the oil and emulsion phases for AA activity. It follows that Chemical B becomes more oil soluble at higher brine concentrations (Table 5), which explains its much better performance at 1.70 mol·kg−1 sodium chloride. This is also echoed visually in Figure 3 (bottom), where from (1.02 to 1.70) mol·kg−1 sodium chloride, the color of the aqueous phase changes from orange to clear, and the water phase shrinks back to the original level. Based on this study but not tested here, it is speculated that Chemical B would begin to perform as an AA at around 1.02 mol·kg−1 sodium chloride, where this visual change, indicating a major shift in solubility, is first detected.
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CONCLUSION Our study has validated the known trend that AAs perform better at higher salinities; however, we have also shown that the salinity level at which the performance result changes can be affected by surfactant structure and relative partitioning between oil and aqueous phases. We observed that greater partitioning of AAs into the oil and emulsion phases, such as that which occurs at higher brine concentrations, directly correlates to a positive performance outcome. We have also demonstrated how simple salinity scans with crude oil performed on the benchtop can help predict performance trends for different AAs. This study sheds some light on the mechanism of AA performance in terms of surfactant properties and lays the foundation for future studies with different chemistries and oil systems.
Figure 3. Oil and brine distribution with Chemical B after 2 min of mixing at room temperature (top) and after 2 days at 4 °C (bottom). Salinity conversions: 0 % = 0 m, 1 % = 0.17 m, 2 % = 0.34 m, 3 % = 0.51 m, 4 % = 0.68 m, 5 % = 0.86 m, 6 % = 1.03 m, 7 % = 1.20 m, 8 % = 1.37 m, 9 % = 1.54 m, 10 % = 1.71 m.
Table 4. LC-MS Data for Chemical A in Oil and Water Phases after 4 d of Partitioning at 4 °Ca m/mol·kg−1
Wb/ppm
Ob/ppm
Ec/ppm
0.34 1.70
565 1562
2815 40266
70220 40772
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ASSOCIATED CONTENT
S Supporting Information *
a
m = molality of brine solution; W = amount of chemical in the water layer; O = amount of chemical in the oil layer; E = emulsion loss. bOne sample was analyzed ten times, giving a relative standard deviation (% RSD) of 6.7 %. cCalculated data.
(1) Salinity scan procedure and (2) LC-MS procedure. This material is available free of charge via the Internet at http:// pubs.acs.org.
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chemical to perform as an AA, its presence in the oil or emulsion layer is favorable, and our results indicate the same.10 In the case of Chemical B, a significant amount of chemicalmore than halfis present in the aqueous phase at 0.34 mol·kg−1 sodium chloride, as shown in Table 4. Accordingly, the vials containing (0 to 0.85) mol·kg−1 sodium chloride look essentially the same (Figure 3, bottom), and it is visually apparent that the orange-colored AA product is partitioning into the water. Furthermore, the water level in these vials is slightly higher than the original water level (red dotted line), also indicating that the chemical is going into the water phase. The data in Table 5 and the observations in Figure 3 (bottom) correlate with the observed lack of performance of Chemical B at 0.34 mol·kg−1 sodium chloride, because there is
AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected]. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS The authors would like to thank Chris Durnell and supporting members of Nalco Champion Diagnostic Solutions for the analytical work. We also thank Dr. Sumit Kiran, Nalco Champion, for the help and guidance in the phase behavior and salinity studies. Finally, we would like to thank Nalco Champion, an Ecolab Company for allowing us to publish this work. 354
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