Characterization of Crude Oils That Naturally Resist Hydrate Plug

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Characterization of Crude Oils That Naturally Resist Hydrate Plug Formation Zachary M. Aman, William G.T. Syddall, Agnes Haber, Yahua Qin, Brendan Francis Graham, Eric F May, Michael L. Johns, and Paul F. Pickering Energy Fuels, Just Accepted Manuscript • Publication Date (Web): 01 May 2017 Downloaded from http://pubs.acs.org on May 2, 2017

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Characterization of Crude Oils That Naturally Resist Hydrate Plug Formation Zachary M. Aman*1, William G.T. Syddall*2, Agnes Haber1, Yahua Qin1, Brendan Graham1, Eric F. May1, Michael L. Johns1, Paul F. Pickering2 1. The University of Western Australia, School of Mechanical and Chemical Engineering, 35 Stirling Hwy M050, Crawley WA, 6151, AUSTRALIA 2. Woodside Energy Ltd., 240 St. Georges Terrace, Perth WA, 6000, AUSTRALIA

The high operating pressures and distances of deep water tiebacks increase the likelihood of hydrate blockage during transient operations such as shut-in and restart. In many cases, complete hydrate avoidance through chemical management may become cost prohibitive, particularly later in the field’s life. However, a subclass of crude oils has been observed in which hydrate blockages do not form during restart, rendering active hydrate prevention unnecessary. Over the last 20 years, limited information has been reported about the chemical or physical mechanisms that enable this plug-resistive behavior. This study presents an extensive and systematic method of characterizing whether an oil may naturally resist hydrate plug formation, including (i) chemical and physical property analysis; (ii) water-in-oil emulsion behavior; and (iii) the effect of the oil on hydrate blockage formation mechanics. This last set of experiments utilizes both a high-pressure rheometer and a sapphire autoclave to allow direct observation of hydrate

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aggregation and deposition, combined with resistance-to-flow measurements. The effect of shutin and restart on the oil’s plugging tendency is also studied in these experiments. The method was tested with seven petroleum fluids, some of which naturally resisted plugging-type behavior even at hydrate volume fractions up to 50%. Most of the fluids presented in this study did not form stable water-in-oil emulsions, but did form stable, non-agglomerating hydrate-in-oil dispersions; the oils suppress hydrate formation rates and their resistance-to-flow does not increase significantly even when the amount of hydrate present would normally result in a plug.

Keywords: gas hydrate, plug formation, non-plugging oils, agglomeration, deposition Corresponding: *Z.M. Aman: +61 8 6488 3078; [email protected] *W.G.T. Syddall: +61 8 9348 4000; [email protected]


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1 INTRODUCTION Gas hydrates are ice-like inclusion compounds, where a molecular cage of water surrounds light hydrocarbon ‘guest’ species such as methane.1 Hydrates are stable at high pressure and low temperature conditions, which often arise in subsea oil and gas flowlines. After a variable induction time inside the hydrate stability zone, solid nucleation will commonly proceed at the water-hydrocarbon interface2 where the guest species is readily available.3 In severe cases, hydrate formation may completely plug the flowline, resulting in costly remediation efforts.4 Turner et al.,5 in collaboration with J. Abrahamson, proposed a four-step mechanism to describe hydrate plug formation in oil-continuous systems (Figure 1): (i) emulsification of liquid water in the continuous oil phase, which was discussed by Boxall et al.;6 (ii) hydrate shell growth around the water droplet;7 (iii) particle aggregation through capillary liquid bridges8 and deposition on the pipeline wall;9 and (iv) aggregate jamming, which increases viscous forces and, for a fixed pressure drop, reduces or eliminates flow.10

Figure 1. Conceptual mechanism of hydrate plug formation in oil-continuous systems, adapted from Turner et al.5


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In this work, we have used the terms hydrate plug and hydrate blockage to represent a system wherein the required momentum driving force to generate flow exceeds the potential energy available from the oil reservoir. Previous studies by Sjöblom et al.11 reported experimental studies on a class of oils wherein moderate hydrate volume fractions would not result in plugging-type behavior. Qualitative observations from the field led to these oils being labeled as “magic” or “non-plugging”, and Sjöblom et al.11 proposed that the functional explanation for their behavior was related to the adsorption of naturally-occurring organic surfactants on the water-oil and hydrate-oil interfaces. Sjöblom et al.11 noted that these surfactants are typically acidic, providing dual stabilization of water-in-oil emulsions. This hypothesis follows the wellestablished hydrate management strategies of anti-agglomerant injection12 and cold flow13, which propose to prevent hydrate plug formation (Figure 1) by eliminating cohesive and adhesive forces.

Microscopic studies on non-plugging oils have demonstrated a statistically significant correlation between the likelihood of crude oil plugging and the amount of organic acid in the oil;14 biodegradation of the oil within the reservoir irreversibly increases and broadens the oil’s content of acidic compounds. These acids may function to reduce the water wettability of the hydrate surface or the stability of a capillary water bridge between two hydrate particles, thereby reducing the aggregation potential between particles.8 Erstad et al.15 connected hydrate-specific activity to the presence of polyfunctional, weakly polar organic acids containing carbonyl moieties. The reservoir biodegradation process was linked by Fafet et al.16 to the appearance of polynuclear aromatic groups, which suggested one potential pathway to the generation of hydrate-active acids. Aman et al.17 observed enhanced adsorption density of polynuclear


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aromatic acids on cyclopentane hydrate surfaces, when compared to water-oil interfaces. These fundamental studies provide a species-level context for the adsorption of specific compounds on the hydrate surface, as proposed by Sjöblom et al.11, to explain non-plugging behavior.

The leading formulation to connect hydrate slurry resistance-to-flow (i.e. apparent slurry viscosity) with hydrate cohesive force and shear rate was proposed by Camargo and Palermo18 and later expanded by Sinquin et al.19 The fundamental equation is shown in equation (1), where dA and dp respectively represent hydrate aggregate and particle diameters, f is the fractal dimension of the aggregate, FA is the hydrate interparticle cohesive force, Φ and Φmax are, respectively, the hydrate volume fraction and maximum packing fraction (4/7), µ0 is the continuous phase viscosity, and γ is the shear rate: 2

d  A   d  p

4− f

3− f  d   φ  A FA 1 −  φ  d   max p   − =0  d   dp2 µ0γ 1 − φ  A  3− f    dp  

(1)

This relationship has been used by Davies et al.,20, Boxall et al.,21 and Zerpa et al.22 to calculate the effect of hydrate formation on pressure drop in multiphase systems, and has been implemented by Aman and co-workers23 in a stand-alone tool to assess the likelihood of hydrate plug formation. Equation (1) is traditionally solved for the aggregate diameter in cases where the cohesive force can be directly estimated and the continuous phase shear stress is calculated from the product of the continuous phase viscosity and shear rate. The form of this equation provides an alternative framework to extend the previous interpretation of Sjöblom et al.11 for non-


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plugging oils. Natural surfactants that reduce the hydrate cohesive force may not be required to prevent hydrate plug formation in cases where either the continuous phase viscosity or the shear rate are appreciably high. This force balance provides a context from which to interpret the experimental methods and results presented below. In this study, we have conducted a comprehensive laboratory-based characterization of hydrate plug formation to assess nonplugging behavior in seven petroleum fluids.

The characterization of non-plugging oils provides crucial information to support a pivotal business decision in deep water oil and gas investments, where the traditional engineering approach is to prevent the system from ever cooling inside the hydrate stability zone. Insulating or burying the pipeline, and depressurizing the line on shut-in, may prevent hydrate formation for tieback distances below 30 km in moderate water depths. However, adding insulation may significantly increase the cost of the flowline. For long-distance and deep water tiebacks where insulation is not financially viable, the injection of thermodynamic hydrate inhibitors is required; these anti-freeze chemicals may cost up to 25 USD per barrel of water produced.24 Sloan, Koh and Sum25 estimated that the capital expenditure associated with complete hydrate prevention is on the order of USD 500 million for a typical deep water development. With some exceptions, the identification of non-plugging oils may allow a development to proceed by reducing or even eliminating the required investment and significantly improving the production economics.

2 EXPERIMENTAL METHODS Three suites of experiments were used to characterize the likelihood of hydrate plug formation of a given oil: (i) chemical and physical oil properties, (ii) water-in-oil emulsion stability, and (iii) flow characteristics of hydrate-in-oil dispersions. The first suite was designed to determine


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the fundamental properties, such as density and viscosity, that are central to both emulsion and dispersion stability models: (i) basic solids and water content – BS&W; (ii) water-oil interfacial tension – IFT; (iii) petroleum fluid assessments of saturates, resins, asphaltenes, and resins – SARA; (iv) gas chromatography – GC – analysis of both the crude oil and petroleum fractions; and (v) petroleum fluid rheology. The second experimental suite followed the heuristic of Sjöblom et al.,11 which aimed to interpret the likelihood of hydrate plugging through the lens of water-in-oil emulsion stability. Three experimental methods were deployed: (i) bottle stability tests – BST; (ii) NMR-based droplet size distribution – DSD – measurements; and (iii) water-in-oil emulsion rheology. The third suite of experiments was designed to provide a comprehensive assessment of how hydrate particles behave in the presence of petroleum fluids. Four experimental apparatus were deployed in this assessment: (i) micromechanical force – MMF – measurements of hydrate cohesion; (ii) differential scanning calorimetry – DSC – of hydrate-in-oil dispersions; (iii) rheology of the hydrate-in-oil slurry; and (iv) hydrate growth rate and plug formation in a highpressure visual autoclave – HPVA. The combination of these hydrate-specific experimental methods was deployed with the objective of characterizing how hydrate particles interact in this specific crude oil; the tests were not designed to characterize hydrate formation behavior. In the field, a combination of natural gas components will produce a structure II hydrate. This study used a cyclopentane (structure II) hydrate system in the MMF, but deployed ultra-high purity methane gas to form structure I hydrate in the DSC, rheometer, and HPVA. While Sloan and Koh1 have demonstrated mild differences in thermophysical properties between both hydrate structures, methane was used to preserve a reliable estimate of hydrate-in-oil volume fraction with decreasing pressure; the denuding1 of a structure II natural gas mixture during hydrate


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formation would introduce uncertainty in the total hydrate volume fraction, limiting the ability to compare hydrate particle behavior between experiments.

2.1 SARA Analysis of Petroleum Fluids Each pure petroleum fluid was diluted volumetrically 30:1 with n-heptane and mixed vigorously by hand for five minutes in a one-litre Schott bottle. The mixture was sealed and isolated for 24 hours at 20°C to allow for asphaltene precipitation. The mixture was then filtered through a 0.45-micron nylon paper to collect the asphaltenes, which were dried for 24 hours at 60°C. The nylon paper was then weighed to determine the mass fraction of soluble asphaltenes in the original petroleum fluid. We note that altering the solvent or filter size would change the type and amount of asphaltenes obtained, and have attempted herein to follow a general convention within the field.26

The saturates, aromatics, and resins were sequentially extracted from the remaining mixture, respectively with heptane, toluene, and a 50:50 v/v methanol-toluene mixture on a rotary evaporator; each extracted petroleum fraction was then weighed. The residual mass between that of the original sample and the sum of the masses of each petroleum fraction was classified as volatile, corresponding to components that have a normal boiling temperature below about 50 °C.

2.2 Gas Chromatography of Petroleum Fluids GC measurements of relevant petroleum fractions were collected on an Agilent GC 7890, equipped with a Flame Ionization Detector (FID). Prior to injection in the GC, each oil sample was further diluted with toluene to prevent flow blockages from occurring in the GC column.


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Two microlitres of each fluid/fraction were injected, and the column temperature was increased from 50 to 320 °C over 30 minutes, with a 10 minute hold after the ramp was completed. The GC analysis was completed for the petroleum fluids discussed below, and for three of the extracted sub-fractions (saturates, aromatics, and resins). The results were collected over GC retention times of 3 to 40 minutes, to exclude the initial toluene peak; this residence time range corresponds to boiling points of C8 through C45. The results were used to qualitatively determine the extent of reservoir biodegradation, which manifests in the chromatogram as an unresolved complex mixture (UCM) dominating moderate retention times (10-30 minutes).

2.3 Water-in-Oil Emulsion Preparation Emulsions were generated using each petroleum fluid of interest in combination with a synthetic brine, consisting of 3.5 wt% NaCl in deionized water; brine was used in preference to pure deionized water, as the interfacial activity of natural surfactants in crude oil may change when ions are present in the aqueous phase.27 Water-in-oil emulsions were generated using a four-step procedure: (i) a sample of the petroleum fluid was placed in a 250 ml Schott glass bottle with homogenizer blades inserted and rotated at 17,800 RPM; (ii) brine was added dropwise to the oil during mixing, taking care to prevent water droplets from contacting either the homogenizer shaft or bottle walls; (iii) the homogenizer was operated for six minutes to ensure the total mixing energy imparted was constant, independent of the total water added; and (iv) the emulsion containers were sealed and maintained at constant temperature for 24 hours prior to any use. Emulsions were prepared with watercuts ranging from 30 to 90%, defined herein as the aqueous volume fraction of the liquid phase. At 90% watercut, a continuous water phase was observed in each crude oil system, while emulsions remained metastable at 30% watercut (discussed in Section 3.1).


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2.4 Basic Solids and Water Characterization in Petroleum Fluids In each test, 25 ml of a crude oil sample was transferred into a graduated cylinder and diluted with 25 ml of high-purity toluene (>99% Sigma-Aldrich); the toluene was pre-saturated with water at 60°C for 24 hours prior to mixing. The mixed fluids were stirred vigorously by hand for three minutes and spun at 4000 RPM in a centrifuge over 20-minute intervals until no further changes were observed in the phase distribution. High-resolution photographs were taken after each centrifuge cycle, and the images were analyzed using ImageJ28 to determine the water content of each crude oil.

2.5 Water-Oil Interfacial Tension The interfacial or surface tension between brine and liquid hydrocarbon was measured using a ThetaLite TL101 optical tensiometer from Attension Instruments. This IFT technique used a pendant drop, where the interfacial tension was determined by visually measuring the droplet’s curvature and volume for a known density difference between both fluid phases; the TL101 instrument uses an in-built algorithm to determine the volume based on the contrast of the wateroil boundary and regression of a model surface to that boundary. The focal distance of the tensiometer’s microscope was calibrated directly using a steel ball of known diameter, and was confirmed before each experiment by measuring the surface tension of a deionized water droplet in air. The pendant drop IFT measurements had a typical repeatability of ± 1 mN/m over six independent trials. An extended discussion of IFT measurement and interpretation in gas hydrate-related systems is available from Aman et al.17

2.6 Nuclear Magnetic Resonance Characterization and Droplet Size


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Samples of both the pure petroleum fluid and its water-in-oil emulsion were placed in quartz sample tubes and analyzed in an ACT-Aachen 1 Tesla Halbach Array permanent magnet, which operated at a 1H resonance frequency of 43 MHz. This apparatus provided sufficient spectral resolution to distinguish between water and liquid hydrocarbon. When testing the pure petroleum fluids, free induction decay (FID) NMR measurements provided an excellent quality control check of the BS&W measurement; there was a 180 Hz shift between aqueous and aliphatic hydrogen peaks. The FID measurement also provided an indication of the aromatic hydrogen content in the samples, which was shifted by 230 MHz from the aliphatic hydrogen peak; the aromatic fraction was further measured through GC analysis (discussed below). The DSDs for each water-in-oil emulsion were measured using the same apparatus, configured with a pulsed field gradient (PFG). This method used a gradient pulse duration of 4 ms with a 250 ms observation time, with 32 repeat scans and a gradient of 0 to 1 T/m over 16 steps. The NMR signal intensity was transformed into an aqueous droplet size distribution via Tikhonov regularization.29-30 The DSD measurements were performed by first sampling an existing emulsion (prepared by the procedure outlined in Section 2.3) into a quartz cylinder, taking care to avoid any free water that may have clarified and separated at the bottom of the vessel. Accordingly, the resultant droplet size distributions represent only the volume of water remaining emulsified in oil when the measurement was performed; the volume of water in the free water phase is determined from BST results, as described above. In practice, each NMR DSD required approximately 15 minutes to collect and sample. The DSDs presented below were normalized to the mode of the droplet sizes, to improve comparison between emulsions with different watercuts. A comprehensive description of the droplet size regularization and measurement procedure is provided by Johns.31


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2.7 Differential Scanning Calorimetry The stability of hydrate-in-oil dispersions was quantified with a Setaram BT 2.15 Tian-Calvet heat flow calorimeter, where a liquid nitrogen supply provided an operating temperature range of -196 to 200 °C.32 The calorimeter had a detection threshold of 20 µW for the heating rate used in this work, where the sensitivity of the heat flux sensor varied between 18 and 34 µV⋅m⋅W-1 depending on temperature. A description of the apparatus is provided by Hughes et al.,33 while Aman et al.34 discussed the use of high-pressure DSC to quantify gas hydrate stability in crude oil.

In each DSC experiment, approximately 1 g of ripened water-in-oil emulsion was placed in the sample cell. The vapor space was flushed with methane at 100 bar at 20 °C; the calorimeter manifold was connected to a temperature-controlled ISCO syringe pump to maintain isobaric conditions during all heating and cooling cycles. The experimental cells were cooled from 20 to -40 °C at a rate of 3 °C/h, held for one hour, and heated back to 20 °C at the same temperature. For reference, the methane hydrate equilibrium temperature at 100 bar is 12.9 °C;35-36 hydrate nucleation was confirmed in each trial through a large exothermic signal from in the sample cell.

As the emulsion destabilizes, the mean emulsified water droplet size increases due to coalescence and the total amount of water-oil interfacial area decreases. As hydrate nucleation occurs at the water-oil interface5 with a constant initial interfacial thickness of approximately 2050 microns depending on the system,7 the extent of hydrate nucleation on a short (i.e. one-hour) timescale may be used as a proxy for the total interfacial area in the system. The DSC results provide an attractive and unique dimension to quantify hydrate dispersion stability, as the


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dissociation of hydrate generates small gas bubbles and local turbulence, thereby enabling a simple coalescence mechanism between droplets; this phenomenon was discussed at length by Lachance et al.37 and has recently been deployed by Aman et al.34 to quantify surfactant adsorption in hydrate systems. The relative magnitude of the hydrate endothermic dissociation signal is compared for each successive heating cycle, which provides a quantitative estimate on the degree of dispersion stability. The results are compared directly to the results of the bottle stability tests, to determine whether the formation (or dissociation) of the gas hydrate dispersion is more or less stable than the corresponding water-in-oil emulsion.

2.8 Rheology of Petroleum Fluids, Emulsions and Dispersions The rheological behavior of both the pure petroleum fluids and water-in-oil emulsions was studied with a TA Instruments Discovery Hybrid HR3 controlled stress Rheometer, equipped with both cup-and-bob and vane-blade geometries. Both geometries were enclosed in a Peltier cooling jacket that operates between 0 and 50 °C. The infinite shear rate viscosity of each pure petroleum fluid was first characterized using the cup-and-bob geometry at 20 °C and 1 atm.

The emulsions prepared via Section 2.3 were characterized at ambient pressure using the vane blade geometry. Only emulsions that were stable (i.e. < 1 vol% clarified water phase after 24 hours of ripening) were used in emulsion tests, to minimize signal artifacts caused by phase separation during the measurement. While the use of stable emulsions decreases the risk of hydrate particle rising in the rheometer, which would increase the uncertainty of the rheological measurement, the rheometer cell does not allow for in situ confirmation that hydrate particles remain homogenously distributed in the oil phase. As a consequence, the interpretation of these rheology experiments is constrained to a qualitative comparison with HPVA tests. In each


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experiment, the 24-hour ripened emulsion was transferred to the experimental cell and was presheared at 500 s-1 for 10 minutes, after which a shear ramp was applied from (1 to 500 to 1) s-1 over a 120-minute window. Twenty discrete points were captured along each shear ramp, where software-controlled steady-state sensing was used for each point. For measurements at different temperatures, the Peltier jacket reached thermal equilibrium within five minutes when the fluids were actively mixed; the constant-shear fluid viscosity was used as a proxy to infer the attainment of steady-state.

For the stable emulsion systems described above, hydrate-in-oil slurry rheology was studied through the following six-step procedure adapted from Webb et al.38 First, the water-in-oil emulsion was placed in the magnetically-coupled vane-blade geometry, and the gas phase was evacuated and flushed thrice with methane at 70 bar and 20 °C. Second, mixing was initiated at 500 s-1 under an isobaric condition for 30 minutes; the vane-blade geometry was able to fully saturate the water-in-oil emulsion within approximately 10 minutes, where the emulsion viscosity was used as a proxy measurement to identify steady-state conditions. Third, the experimental cell was isolated and, under a constant shear rate of 500 s-1, the Peltier jacket temperature was decreased to 1 °C at a rate of 2 °C/h. In most trials, methane hydrate nucleated between 1 and 3 hours after reaching the set-point temperature. Fourth, hydrate growth rate was determined in the isochoric system from the decrease in cell pressure, at a constant shear rate of 500 s-1; this measurement procedure allowed for the direct correlation of slurry relative viscosity to the hydrate volume fraction in oil. After the hydrate reaction reached steady-state (typically 10 hours), the fifth step involved a flow ramp from (1 to 500 to 1) s-1 with at least 20 steady-state points; the number of points was increased for hydrate dispersions that showed substantial non-


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Newtonian behavior. The sixth and final step involved shut-in of the hydrate dispersion in the high-pressure vane blade geometry, with a 2% oscillation for 8 hours at 1 °C; after the shut-in period, the shear stress was monotonically increased while shear rate was recorded, to estimate the yield stress of the hydrate-in-oil dispersion.

2.9 Micromechanical Hydrate Cohesive Forces The cohesive force between cyclopentane hydrate particles was measured on a secondgeneration MMF apparatus, where the particles were immersed in cyclopentane liquid containing 0-50 wt% of crude oil. This consisted of an Olympus IX73 inverted light microscope, an LED light source to minimize heat transfer to the sample, placed atop an active pneumatic vibration isolation table. A stainless steel and copper experimental cell was placed on the microscope stage and its temperature regulated with a 50:50 v/v glycol-water mixture that was circulated through a cooling bath. The cell temperature was measured directly using a thermocouple calibrated to ± 0.2 °C. Two Eppendorf Patchman NP2 micromanipulators were mounted adjacent to the experimental cell, each containing a capillary holder and capillary tube. Both capillary tubes were outfitted with carbon fiber cantilevers with outer diameters of approximately 7 microns, where the spring constant of the cantilever was calculated based on a known tensile strength for carbon fiber; the calibration method for the carbon fiber cantilever was described in detail by Morrissy et al.39 The apparatus design was based on a description from Yang et al.,40 with a technique adapted by Aman et al.8

In each experiment, droplets of deionized water were placed on the tip of each cantilever and submerged in liquid nitrogen to form ice. The experimental cell was filled with liquid cyclopentane (>99% Sigma-Aldrich), a structure II hydrate-forming guest at ambient pressure


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below 7.7 °C;1 the cyclopentane was initially cooled to -5 °C. The cantilevers and ice particles were quickly transferred to the cyclopentane bath to maintain ice stability and the bath temperature was raised to a set-point of 2 °C. Upon crossing the ice phase boundary, the melting ice crystal provided a template to reliably grow sII cyclopentane hydrate. The particles were allowed to anneal for 30 minutes at 2 °C. After this point, 40 “pull-off” measurements were performed between the cyclopentane hydrate particles according to a four-step procedure:41 (i) the top particle was lowered into contact with the bottom particle at an preload force of 1.7 mN/m, which is scaled by the harmonic mean radius of the particle pair; (ii) the particles were allowed to rest in contact for 10 seconds; (iii) the top particle was raised at constant velocity – approximately 1 micron/second – until the particles broke apart; and (iv) the maximum separation distance on cohesive failure was captured by the camera. The cohesive force was determined via Hooke’s law as the product of the cantilever spring constant and the maximum displacement, which was determined from the image processed with ImageJ.28 After the baseline forces were measured, 1-3 wt% of crude oil was injected in the experimental cell and mixed by hand with a glass capillary for five minutes, which has been found to be sufficient for natural surfactants to adsorb to the hydrate-oil and/or water-oil interfaces.17 An additional 40 pull-off measurements were performed in the crude oil system, and the results were bench-marked against the baseline measurement. In this study, MMF results were combined with the IFT results to determine the strength of natural surfactants in each crude oil that may adsorb to the hydrate-oil or water-oil interfaces, respectively. A comprehensive description of the MMF technique applied to crude oil systems was presented by Dieker et al.41

2.10 High-Pressure Visual Autoclave


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The severity of hydrate plug formation was studied using a high-pressure sapphire visual autoclave apparatus containing a vane-and-baffle impeller system, which was presented in detail by Akhfash et al.42 In short, the apparatus consists of a DB Robinson-type sapphire cell, which is submerged in a glycol-water cooling bath; the cell ID was 25.4 mm, with a wall thickness of 6.4 mm and a height of 150 mm. The glycol bath temperature was controlled by a LabView PID algorithm, where intermittent power was applied to a 1100 W cartridge heater while heat was continuously being removed by a ThermoFisher immersion cooler (IP-40 NC, with 3-inch coil). Cell contents were mixed by a magnetically-coupled HiTec Zang ViscoPakt Rheo 57 adjustable speed motor, capable of running between 40 and 2000 RPM; the motor provides a direct torque measurement over the range (0.04 – 57) N⋅cm. The cell and bath temperatures were measured with 100Ω platinum resistance thermometers (PRTs) with uncertainties of ±0.2 K; the cell pressure was monitored with an Omegadyne strain-gauge pressure transducer, rated to 320 bar with an uncertainty of ±0.085 bar. Hydrate formation was detected by a sharp decrease in cell pressure inside the hydrate region. As the cell operated in isochoric mode, hydrate volume fraction was estimated from the decreasing cell pressure during hydrate growth, where a constant hydration number (5.75)1 was coupled with molar volume estimates from Multiflash 4.1 using the CPA model set.43

In each experiment, the severity of hydrate plug formation was assessed through the following procedure: 1. The sapphire cell was filled with 18 ml of brine and crude oil, at the target watercut. This liquid loading condition is sufficient to fully submerge the impeller blades without generating an unmixed volume. The fluids were not homogenized beforehand.


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2. The gas phase was flushed three times with 20 bar ultra-high purity methane (99.999%), and was finally charged to approximately 75 bar at 20 °C. 3. The cell was initially mixed at 1000 RPM for at least 30 minutes to ensure fluids were fully saturated with methane, and the PID cooling system was set to 1 °C at a rate of 1 °C/h. 4. As the system crossed the hydrate equilibrium boundary, the mixing system was deactivated; after achieving a minimum temperature of 1 °C, fluids were left for 24 hours to simulate shut-in conditions. Typically, less than 1 vol% hydrate grew during this shut-in period, due to the lack of mixing. 5. To simulate restart, the mixing system was engaged directly to 1000 RPM. 6. After the hydrate reaction reached steady state, the glycol-water bath was warmed to 20 °C at a rate of 2 °C/h to give complete dissociation.

3 RESULTS AND DISCUSSION Seven petroleum fluids were characterized in this study (Table 1): five crude oils (labeled A-E) and two condensates (labeled F-G). The inherent water content of each condensate fluid was below the detectable limit (0.01 vol%). This water content analysis was also confirmed by NMRFID measurements, with fluids B-G with less than 1 vol% water while the water peak observed in Oil A was of similar intensity to the aliphatic peak. All the petroleum fluids contained a moderate aromatic hydrogen peak. Density was measured volumetrically using a balance with microgram resolution, with a 95% confidence bound of 0.02 g/ml.


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Energy & Fuels

Table 1. Characterization of petroleum fluids used in this study. Density and viscosity were measured at atmospheric pressure. Fluid A B C D E F G

Inherent water (vol%) 46 0.028 0.046 0.024 0.4 0 0

WaterOil IFT (mN/m) 30 22 41 33 17 31 23

Saturates (mass%)

Aromatics (mass%)

Resins (mass%)

Asphaltenes (mass%)

49.26 79.96 77.1 83.32 66.06 46.25 30.97

3.05 4.06 4.2 3.99 4.95 1.35 0.23

0.9 0.56 0.87 0.58 0.18 0.22 0.35

0.14 0.24 0.21 < 0.01 0.08 0.04 < 0.01

Density (20 °C, g⋅ml-1) 0.91 0.91 0.87 0.87 0.81 0.70 0.71

Viscosity (20 °C, cP)

Viscosity (5 °C, cP)

593 165 132 69 10 50 vol%) hydrate-in-oil dispersions without severe increases in resistance-to-flow metrics. At 30% watercut, the data show that emulsions of these oils (A-D in Table 1) begin to break after approximately 24 hours, due to a lack of natural surfactants that are active at the water-oil interface. Despite this condition, the moderate-to-high densities (> 0.87 g/ml) and viscosities (211-2863 cP at 5 °C and 1 bar) prevent hydrate deposition on the wall. Without a transient build-up mechanism (e.g. wall deposition), resistance-to-flow is limited to particle aggregation in the continuous phase. A comparison between the rheological data obtained and established hydrate aggregation models suggests that these low-likelihood fluids may allow the formation of low-to-moderately fractal aggregates, but that these aggregates only increase resistance-to-flow by less than a factor of 2 even for hydrate volume fractions above 30%.

Acknowledgements The authors acknowledge Prof. Ken Marsh for his donation of the sapphire cell, and Mr. David Amm for apparatus design and construction. EFM acknowledges Chevron for the Gas Process Engineering Endowment that has supported apparatus construction and maintenance.


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38. Webb, E. B.; Rensing, P. J.; Koh, C. A.; Sloan, E. D.; Sum, A. K.; Liberatore, M. W., High-Pressure Rheology of Hydrate Slurries Formed from Water-in-Oil Emulsions. Energy & Fuels 2012, 26 (6), 3504-3509. 39. Morrissy, S. A.; Lim, V. W.; May, E. F.; Johns, M. L.; Aman, Z. M.; Graham, B. F., Micromechanical Cohesive Force Measurements Between Precipitated Asphaltene Solids and Cyclopentane Hydrates. Energy & Fuels 2015, 29 (10), 6277-6285. 40. Yang, S.-o.; Kleehammer, D.; Huo, Z.; Sloan, J., E Dendy; Miller, K., Temperature dependence of particle-particle adherence forces in ice and clathrate hydrates. Journal of Colloid and Interface Science 2004, 277, 335-341. 41. Dieker, L. E.; Aman, Z. M.; George, N. C.; Sum, A. K.; Sloan, E. D.; Koh, C. A., Micromechanical Adhesion Force Measurements between Hydrate Particles in Hydrocarbon Oils and Their Modifications. Energy & Fuels 2009, 23, 5966-5971. 42. Akhfash, M.; Boxall, J. A.; Aman, Z. M.; Johns, M. L.; May, E. F., Hydrate Formation and Particle Distributions in Gas-Water Systems. Chemical Engineering Science 2013, 104, 177188. 43. Infochem Multiflash for Windows 4.1, Infochem Computer Services Ltd: London, 2012. 44. Neumann, A. W.; David, R.; Zuo, Y., Applied Surface Thermodynamics. Second Edition ed.; Taylor & Francis Group: Boca Raton, FL, 2010. 45. Lake, L. W.; Fanchi, J. R., Petroleum Engineering Handbook. Society of Petroleum Engineers: 2006; Vol. Volume 1: General Engineering. 46. Oliveira, R. C. G.; Gonçalves, M. A. L. In Emulsion Rheology - Theory vs. Field Observation, Offshore Technology Conference, Houston, Houston, 2005; p OTC 17386. 47. Einstein, A., Berichtigung zu meiner Arbeit: Eine neue Bestimmung der Moleküldimensionen. AnnIn Phys. 1911, 34, 591-592. 48. Einstein, A., Eine neue Bestimmung der Moleküldimensionen. AnnIn Phys. 1906, 19, 289-306. 49. Taylor, G. I., The Viscosity of a Fluid Containing Small Drops of Another Fluid. Proceedings of the Royal Society of London. Series A, Containing Papers of a Mathematical and Physical Character 1932, 138 (834), 41-48. 50. Aman, Z. M.; Joshi, S. E.; Sloan, E. D.; Sum, A. K.; Koh, C. A., Micromechanical Cohesion Force Measurements to Determine Cyclopentane Hydrate Interfacial Properties. Journal of Colloid and Interface Science 2012, 376 (1), 283-288. 51. Mills, P., Non-Newtonian behaviour of flocculated suspensions. Journal de Physique Lettres 1985, 46 (7), 301-309. 52. Cameiro, A.; Fezoua, A.; Ouabbas, Y.; Herri, J.-M.; Darbouret, M.; Sinquin, A.; Glenat, P., Agglomeration of Gas Hydrate in a Water-in-Oil Emulsion: Experimental and Modeling Studies. In 7th International Conference on Gas Hydrates Edinburgh, United Kingdom, 2011. 53. Cameirao, A.; Fezoua, A.; Ouabbas, Y.; Herri, J.-M.; Darbouret, M.; Sinquin, A.; Glenat, P., Agglomeration of Gas Hydrate in a Water-in-Oil Emulsion: Experimental and Modeling Studies. In 7th International Conference on Gas Hydrates, Edinburgh, 2011; pp 1-8. 54. Joshi, S. V.; Grasso, G. A.; Lafond, P. G.; Rao, I.; Webb, E.; Zerpa, L. E.; Sloan, E. D.; Koh, C. A.; Sum, A. K., Experimental flowloop investigations of gas hydrate formation in high water cut systems. Chemical Engineering Science 2013, 97, 198–209. 55. Di Lorenzo, M.; Aman, Z. M.; Kozielski, K.; Norris, B. W. E.; Johns, M. L.; May, E. F., Under-inhibited hydrate formation and transport investigated using a single-pass gas-dominant flowloop. Energy & Fuels 2014, 28 (11), 7274–7284.


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Characterization of Crude Oils That Naturally Resist Hydrate Plug

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