OTC-31712-MS

Jose G. Delgado-Linares, Mathias Pohl, and Ahmad A. A. Majid, Colorado School of Mines; Chitose Yoda andNorio Tanaka, Yokogawa Electric Corporation, Omega Simulation Co., Ltd; Luis E. Zerpa, Manika Prasad, andCarolyn A. Koh, Colorado School of Mines
Copyright 2022, Offshore Technology Conference DOI 10.4043/31712-MS
This paper was prepared for presentation at the Offshore Technology Conference held in Houston, TX, USA, 2 – 5 May, 2022.
This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents ofthe paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any
position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the writtenconsent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may
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Abstract
The detection of asphaltene precipitation and gas hydrate formation is critical to preventing production
losses and to optimize strategies for mitigation and remediation. Likewise, the evaluation of some flow
properties (e.g., viscosity and yield stress) of the slurries formed for asphaltenes and hydrates are paramountwhen developing and testing prediction tools for safe field operations. Several complications must be
considered when dealing with asphaltenes and hydrates at field conditions, e.g., harsher conditions(especially high or extremely high pressure), the variation of fluid composition over time, and the lack of
information on the thermodynamic conditions at which those solids (asphaltenes and hydrates) form. One
possibility to face this challenge is to use field information to calibrate existing prediction models/tools andmake them applicable for new field conditions. Hence, there is interest in industry to develop new tools thatallow the detection of asphaltenes and hydrates in the early stages of their formation.
In this work, acoustic and nuclear magnetic resonance (NMR) measurements are utilized to detect
asphaltene precipitation in crude and model oils. Asphaltene detection was performed at ambient pressure
and at CO2 pressurized conditions. Acoustic and NMR measurements were sensitive to the asphaltene
concentration in the tested oils. In addition, rheological properties such as viscosity and yield stresswere determined for hydrate slurries in crude oil systems at different water volume fractions, salt (NaCl)
concentrations and gas compositions. Gas hydrate slurry formed from a CO2-rich gas exhibited a phase
inversion in rheological experiments (external phase changed from oil to water), which was possibly
promoted by the CO2-activated natural surfactants of the crude oil.

Introduction

Solids such as asphaltenes and hydrates represent a serious problem in the crude oil production process.
Those solids may reduce or even arrest hydrocarbon production due to blockage of transmission lines(Ellison et al., 2000; Gudmundsson, 2017). Given that asphaltenes and hydrates form by different
mechanisms with significantly different time scales, the effectiveness of the avoidance/mitigation strategies

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Early Detection and Assessment of Asphaltene Precipitation and Gas
Hydrate Formation at Field Conditions

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Figure 1—Schematic of Yen-Mullins model of asphaltenes, indicating the different stages of asphaltene aggregation.

The reduction in asphaltene solubility may be induced mainly by: a) addition of liquid paraffinichydrocarbons, b) pressure reduction close to the crude oil bubble point, and c) addition of CO2. In all
the three situations, a local composition change is induced and the solvent capacity of the oil towards
asphaltenes decreases, and thus the aggregation/precipitation mechanisms can take place (da Silva et al.,2014; Hammami & Ratulowski, 2007; Wang et al., 2017). Likewise, it has been demonstrated that in general
the precipitation of asphaltenes increases with the CO2 concentration in the system (Deo & Parra, 2012;
Fakher et al., 2020; Lei et al., 2010; Zanganeh et al., 2012).
Asphaltene detection at field conditions is a challenge faced by the industry due mainly to the highpressures encountered in problematic locations. With the aim to overcome this problem, several techniques
have been developed, namely: a) gravimetric measurements, b) acoustic resonance, c) light scattering, andd) filtration. All of these techniques show some potential application, however aspects such as the lackof sensitivity, subjective interpretation, or being time consuming are the main drawbacks in considering
them as a definitive solution (Jamaluddin et al., 2002). It is worth mentioning that the accurate detectionof the asphaltene precipitation and deposition in the early stages allows for the effective application for
remediation/avoidance techniques, e.g., injection of aromatic solvents or chemical dispersants (Gharbi etal., 2017; Kelland, 2016).
Gas hydrates are inclusion solid compounds in which small molecules (e.g., methane or CO2) are trappedby a hydrogen-bonded network. In general, they occur at low temperatures and high pressures (Sloan &Koh, 2007), which are very common conditions encountered in oil and gas production lines, mainly inDownloaded from http://onepetro.org/OTCONF/proceedings-pdf/22OTC/4-22OTC/D041S046R005/2678383/otc-31712-ms.pdf/1 by Colorado School of Mines user on 10 May 2022

strongly depends on the knowledge of the thermodynamic and kinetic conditions of their formation and theaccuracy of the detection techniques applied in the field.
Asphaltenes represent the heaviest and most polar crude oil fraction. From an operational point of view,
they are defined as the group of compounds insoluble in small paraffins (e.g., pentane or heptane) andsoluble in aromatic solvents (e.g., toluene or xylene) (Speight, 2004). Asphaltene molecular structure has
been subject of debate for many years; however, currently a general consensus seems to be that the mainasphaltene molecule is composed of a polyaromatic core (with ~6 benzene rings) linked to several aliphatic
branches with a average molecular weight of ~750 Da. Heteroatoms, such as oxygen, nitrogen, sulphur
and metals are responsible for the asphaltene polarity and for the aggregation tendency of this crude oil
fraction (Mullins, 2011; Spiecker et al., 2003). Besides their precipitation and deposition in the petroleum
reservoir or in the production tubing, asphaltenes also play a major role in the stabililization of water-incrude oil emulsions (Aguilera et al., 2010; Alimohammadi et al., 2019; Czarnecki & Moran, 2005; Kokal,
2005; McLean & Kilpatrick, 1997).
The asphaltene precipitation occurs when the solubilization power of the medium is reduced andasphaltene molecules self-associate, forming aggregation structures of high molecular weight and eventuallya new solid phase (Buckley et al., 2007; Hammami & Ratulowski, 2007). The sequence of steps involvedin asphaltene aggregation has been established in the Yen-Mullins model, which presents four main
aggregation stages, as shown in Figure 1 (Chen et al., 2020):

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Methods and Materials
Oils
Crude oils. Two crude oils labeled as N1-C and N1-A were used in this study. Table 1 shows some physicalproperties of these oils. Since crude N1-A is an unstable crude oil with asphaltenes originally precipitated,
it was used in experiments where solid asphaltenes in crude oil are needed.
Table 1—Physical properties of the crude oils used
Crude oil

API gravity

Asphaltene content (wt.%)

N1-C

20

2.5

N1-A

29

4.5

Model oil. In experiments carried out with model systems, asphaltenes were dissolved in a mixture tolueneheptane (heptol). Asphaltenes were separated from the crude oil N1-C by adding n-heptane in a heptane/
crude oil ratio (mL/g) of 40. This separation process has been published elsewhere (Aguilera et al., 2010;
Reyes Molina et al., 2021) and is based on the standard IP 143.

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offshore facilities. The operation within the hydrate equilibrium region, even for a short period of time,
represents a risk given that the formation of hydrate plugs is relatively fast (Ellison et al., 2000). During
hydrate formation/plugging in systems where oil is the dominant phase (e.g., crude oil systems), fourmain processes take place: a) water emulsification into the oil phase, b) rapid formation of small hydrate"balloons" composed of partially converted water droplets, c) interaction of hydrate particles throughcapillary bridging, and d) extensive hydrate agglomeration. The occurrence of those processes may be
detected by the change of some fluid properties, such as liquid viscosity (Sloan, 2010; Sum et al., 2012).
Hydrate mitigation strategies may be clasified in one of the two following categories: avoidance ormanagement. Hydrate avoidance aims to keep the system outside of the region of hydrate equilibrium. This
goal can be accomplished by injecting thermodynamic hydrate inhibitors (THIs) such as methanol or mono
ethylene glycol (MEG). Inorganic salts (e.g., NaCl) act as THIs shifting the hydrate formation conditions
towards lower temperatures and higher pressures. On the other hand, hydrate management allows operation
within the hydrate stability region by increasing the time necessary for hydrate formation or reducing thetendency of hydrate particles to agglomerate (Kinnari et al., 2014; Sloan & Koh, 2007). This requires theuse of kinetic hydrate inhibitors (KHI) and/or anti-agglomerants (AAs), respectively. In some crude oils,
natural antiagglomeration can be used as an alternative of hydrate control with no or minimum addition ofcommercial chemicals (Delgado-Linares et al., 2021; Salmin et al., 2021).
As shown above, the ability for early detection of asphaltene precipitation/deposition and hydrate
formation is critical to prevent losses in crude oil production. These flow assurance solids can occur
simultaneously or in different stages of the production process. The application of mitigation methods
just when asphaltenes and hydrates start to appear could reduce the OPEX due to remediation treatments.
Moreover, the evaluation of flow behavior of the slurries generated by those flow assurance solids is also
key in quantifying the energy required for their transportation. In this work, acoustic velocity and nuclear
magnetic resonance (NMR) measurements were used to infer asphaltene precipitation and aggregationin crude oils and model systems. The use of these techniques in laboratory experiments constitutes theinitial step for their further application in the field. Likewise, hydrate formation / flow measurements were
performed to quantitatively assess the slurry rheological properties of hydrate systems under both steadystate and transient (shut-in/re-start) conditions.

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Asphaltenes were dissolved in toluene through ultrasonic stirring bath (60 Hz) for 12 minutes. The
complete dissolution was verified by using an optical microscope. Heptane was then added, and the sample
was stirred in an ultrasonic bath for 4 additional minutes. This kind of model oil has been previously used
to study asphaltene precipitation (Zanganeh et al., 2012).

Gases
Three kinds of gases were used in this work, namely CO2, natural gas, and CO2-rich gas. Table 2 depicts
the composition of the gas mixtures.
Table 2—Composition of the gas mixtures used in this study
Composition

Mole percent (%)
Natural gas

CO2-rich gas

Carbon dioxide (CO2)

7.14

43.80

Methane

79.69

49.80

Ethane7.14

3.00

Propane

4.00

2.00

Butane2.03

1.40

Acoustic measurements
Acoustic measurements were carried out at ambient and at high pressure (500 psig) on model oils (withasphaltenes from crude N1-C) and crude oil N1-A (with and without asphaltenes). By knowing the lengthof the sample and the time it takes for the wave to travel such a length, the velocity in the oil was calculated.
In these experiments, sample holders were used with one transducer on the top and one on the bottom. Oneof the transducers serves as a source, which generates an acoustic wave, and the second transducer serves
as a receiver which records the wave.
To generate the acoustic signal, a pulser is used, and the acoustic wave is digitized on an oscilloscope.
Changes in arrival time as well as wave amplitudes due to the presence of precipitated/deposited asphaltenes
were investigated. Benchtop measurements were conducted on crude N1-A (with and without asphaltenes)
and pressurized experiments (500 psi of CO2) were performed on the model oil (toluene 70% - heptane30%) with varying asphaltene content (asphaltenes from crude N1-C). It is worth noting that asphaltenes
are in a dissolved state at ambient conditions and precipitation could be induced by pressurizing the systemwith CO2 gas.
Nuclear magnetic resonance (NMR)
Ambient and pressurized low field NMR experiments (2 MHz) (Livo et al., 2021) were carried out on oil
samples that contained asphaltenes (crude oil N1-A, and model oil with 0, 1, 2.5, and 4 wt.% asphaltenes
from crude N1-C), as well as on a sample of de-asphalted oil N1-A. T2 relaxation curves were recorded toobserve the changes in relaxation time with and without asphaltenes. Model oils with dissolved asphaltenes
were pressurized with CO2 to induce asphaltene precipitation. The effect of different asphaltene contents in

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De-asphalted oil. A sample of crude N1-A was mixed with heptane in a ratio 20/1 (mL of heptane / gramsof crude oil) and mixed with a magnetic stirrer for 10 mins. The mixture was filtered with a 2.5 μm filter
paper to separate the precipitated solid from the maltenes (de-asphalted oil). Heptane was separated fromthe de-asphalted oil in a rotary evaporator under vacuum condition. The absence of solids was confirmed
by using an optical microscope. Acoustic measurements with de-asphalted crude oil N1-A were comparedwith the whole crude oil in which solid asphaltenes are originally present.

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the model oil on T2 relaxations was analyzed. More details regarding the experimental setup can be foundin Livo et al. (2021).

Emulsion stability in presence of hydrates. High-Pressure Differential Scanning Calorimetry (HPDSC)
Emulsion stability under gas hydrate formation and dissociation was studied by using a microdifferential
scanning calorimeter. In this work, a low emulsion stability under the hydrate formation and dissociation
pathways is an indication of high hydrate particle agglomeration (Majid et al., 2021). In this method, ~15
mg of emulsion sample was needed for evaluation of emulsion stability. The HP-DSC setup has an operating
temperature of −45 to 120 °C and maximum operating pressure of 2,200 psi (15.2 MPa). In these tests, thesample was cooled from 30 °C to the experimental temperature (−5 °C) to form hydrates. The sample wasthen heated back to 30 °C to dissociate the hydrates. These cooling and heating steps (hydrate formationand dissociation) were repeated for an additional two times. The stability of the emulsion upon hydrate
formation and dissociation was evaluated by comparing the amount of hydrates formed in each formation/
dissociation cycle.
Rheological measurements of gas hydrate slurries
Rheological properties of hydrate slurries, such as viscosity and yield stress, were measured using a highpressure rheometer. The apparatus has an operating shear rate of 0.1 to 1000 s-1, an operating temperatureof -40 to 150 °C and can withstand pressures of up to 2000 psi (14 MPa). The high-pressure rheometeris connected to a high-pressure syringe pump to control the pressure of the system and monitor the gas
consumption (for hydrate formation and gas solubilization). In this work, 30 ml of emulsion sample wasinjected into the high-pressure rheometer cell. The system was then pressurized up to 1000 psig. The sample
was stirred at the constant shear outside the hydrate equilibrium condition (20 °C) for 90 minutes to saturate
the oil phase. Two gas compositions were used in this investigation: (1) natural gas composition and (2)CO2-rich natural gas composition (Table 2).
After full saturation, the sample was cooled to the experimental temperature (4 °C) at a rate of 0.5 °C/
min for hydrate formation. The sample was stirred at this condition for 55 hours. Following this step, thesample was put into a shut-in condition (no stirring) for 24 hours. Next, a shear force was slowly exerted
upon the sample to determine the yield stress of the slurries (Majid et al., 2017; Rensing et al., 2011). Afterthe yield stress measurements, ramping tests were conducted whereby the stirring speed was increased anddecreased to observe any hysteresis.

Results and discussion
Asphaltene detection through acoustic measurements
The recorded benchtop acoustic waveforms for crude oil N1-A can be seen in Figure 2. Changes in velocity(inferred from the wave arrival time) were observed in the presence and absence of asphaltenes. The
calculated velocities were lower by 70 m/s (~5%) when asphaltenes were present. The presence of solidasphaltene particles delayed the acoustic wave arrival, decreasing its velocity. Additionally, a reduction in
amplitude after 2 μs was observed in the oil sample that contains asphaltenes suggesting potential effectsof the precipitated asphaltenes on the later part of the acoustic wave, also called the coda.

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Emulsion preparation for hydrate tests
Emulsions were prepared by homogenizing the water into the oil phase at 8,000 rpm for 3 mins. The water
was added dropwise using a syringe during the first minute. This protocol has been used in several publishedworks (Delgado-Linares et al., 2013, Delgado-Linares et al., 2020; Sjöblom et al., 2010).

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These changes indicate a loss in energy and wave velocity as the acoustic wave reverberates in the sample
and small effects in the acoustic path accumulate as the wave covers multiple paths in the sample. The
cumulative effect is enhanced at increasing times (Figure 2).
Figure 3 shows results for the system pressurized with CO2 gas (500 psig) with model oil (toluene 70% heptane 30%) with varying asphaltene contents from crude N1-C. Time equals zero indicates measurements
at ambient conditions before pressurization with CO2. The velocities decrease with increasing asphaltene
content as the density of the model oil mixture increases. Injection of CO2 decreased the velocities for
all three samples immediatly. The largest decrease was observed for the model oil containing the highest
amount of asphaltenes (Table 3). Moreover, changes in the acoustic waveforms and arrival times (Figure 4)
can be observed continuously for samples containing asphaltenes from crude N1-C (2.5 wt.% - Figure 4b),whereas the sample containing no asphaltenes (0 wt.% - Figure 4a) showed only minor changes. The largest
drop in velocities occur immediately after CO2 gas is introduced to the system. CO2 molecules dissolve into
the model oil and cause asphaltenes to precipitate.
Table 3—Percentage changes in velocity for model oils with different asphaltene content
Asphaltene content*after 22 h

0 wt.%

2.5 wt.%

4 wt.%% Change after 1 h (compared to initial velocity)

4.4

4.4

14.4

% Change after 24h (compared to initial velocity)

4.3*

6.6

18.5

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Figure 2—(a) De-asphalted N1-A oil (b) As-is N1-A oil (c) entire wave track for the as-is N1-A crude oil (red) and deasphalted N1-A oil (blue) (d) zoomed wave track for the as-is N1-A crude oil (red) and de-asphalted N1-A oil (blue)

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Figure 4—Continuously recorded ultrasonic waveforms for pressurized (500 psi CO2) (a)model oil without asphaltenes and (b) model oil containing 2.5 wt.% N1-C asphaltenes.

It is noted that besides asphaltene precipitation, CO2 could induce other levels of asphaltene aggregation,
namely formation of nanoaggregates and clusters, as shown by Yen-Mullins’ model in Figure 1.
At low concentration, asphaltenes are generally present in crude oil as a molecular solution.
Nanoaggregates (~six molecules) and clusters (~8 nanoaggregates) occur when the asphaltene concentration
is increased, or the oil composition is changed to reduce asphaltene solubility.
The acoustic wave contains information of the entire fluid mixture (model oil with 70% toluene and 30%
heptane + precipitated asphaltenes from crude N1-C) and is therefore directly affected by the precipitatedasphaltenes and the presence of CO2 (Figure 4). Moreover, although the changes are small after the 2hmark (with respect to acoustic velocities), those changes still indicate that additional asphaltenes are either
continuously being precipitated, or the asphaltenes start to form more complex / larger structures. Bothpossibilities could explain the changes observed in the waveforms (Figure 4b).
Asphaltene detection through nuclear magnetic resonance (NMR)
NMR T2 relaxation curves are shown in Figure 5 for crude oil N1-A with and without asphaltenes.
Precipitated asphaltenes cause a faster relaxation time compared to the same oil without asphaltenes. Longer

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Figure 3—Ultrasonic velocities for pressurized model oils (toluene 70% heptane 30%) with 0 (black), 2.5 (red), and 4 (blue) wt.% of N1 -C asphaltenes.

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relaxation times indicate that protons spin longer. In the presence of asphaltenes the protons cannot spin as
freely, which results in a faster relaxation (Prunelet et al., 2004).

Time-lapse NMR measurements were conducted on model oil system with 30% toluene, 70% heptane
and 2 wt.% asphaltene content. In this mixture ratio, the asphaltenes are unstable and precipitate, as inferredfrom the recorded T2 relaxation spectra in Figure 6. The model oil system (toluene 30% - heptane 70%)
without added asphaltenes shows the longest relaxation time and a single peak. Addition of asphaltenes tothe model oil alters the relaxation peak. Asphaltenes in the model oil result in reduced relaxation time andamplitude. A second relaxation peak develops as asphaltenes start to precipitate (Prunelet et al., 2004). The
T2 response for the model oil with 2 wt.% asphaltenes shows a bimodal distribution pattern. After 17h the
2 peaks started to separate clearly with the larger peak at longer relaxation times approaching the model oil
and the smaller peak relaxes faster by 300 ms, from about 700 ms to 400 ms in Figure 6.

Figure 6—T2 relaxation spectrum for model oil (toluene 30%-heptane 70%) without asphaltenes(blue curve), and model oil (toluene 30% - heptane 70%) with 2 wt.% of asphaltenes at time zero (redcurve) and after 17h (yellow curve). Asphaltenes in the model oil act to reduce relaxation time andamplitude. Asphaltene precipitation is inferred from the second relaxation peak marked by a blue circle.

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Figure 5—T2 relaxation curves for crude oil N1-A with (orange) and without (blue) asphaltenes.

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Figure 7—T2 relaxation spectrum for model oil (toluene 30%-heptane 70%) with 2.5 wt.% crude N1-C asphaltenes at(a) ambient pressure and (b) at 500 psig of CO2 over time. Colder colors to warmer colors indicate time progression.

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NMR relaxation spectrum for model oil (toluene 30% – heptane 70%) containing 2.5 wt.% of asphaltenes
from crude N1-C at ambient and pressurized with 500 psig of CO2 can be seen in Figure 7. At ambientpressure, the observed bi-modal distribution (Figure 7a) is consistent with a decrease in relaxation time
due to dissolved asphaltene observed in Figure 6. After pressurizing the model oil with 500 psig of CO2,
a trimodal distribution was observed in the relaxation spectrum (Figure 7b). One can hypothesise that thepeak at around 10,000 ms correlates to the bulk fluid with the residual dissolved asphaltenes and the fasterrelaxing peaks (∼300 ms and 2,000 ms) correspond to relaxations of the model oil on the surfaces of the
precipitated asphaltenes.
T2 relaxation for model oil (toluene 70% - heptane 30%) with known amounts of N1-C asphaltenes (0,1, 2.5, and 4 wt.%) was measured before and during exposure of 500 psig of CO2 gas (Figure 8 and Figure9). The model oil containing dissolved asphaltenes (Figure 8a) shows a slightly faster relaxation spectrum(1760 ms) when compared to the same model oil without asphaltenes (2230 ms) (Figure 8b). After CO2
pressure was increased to 500 psi, two additional peaks at faster relaxation times (Figure 8c) appeared
and increased in magnitude over time. The peak at longer relaxation times increases with time to longer
relaxations. The blank sample [only model oil (toluene 70% - heptane 30%) without asphaltenes] shows
only minimal changes in T2 amplitudes (Figure 8d) when 500 psig of CO2 is applied. Note that the T2
relaxation in the model oil changes from about 2400 ms (Figure 8b) to almost 12,000 ms at 500 psi of CO2
pressure (Figure 8d). This change is more likely due to viscosity changes and not due to a separation of thefluid phases, which should lead to a bimodal distribution.

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Figure 9—T2 relaxation spectra for model oil (toluene 70% – heptane 30%) and 1 wt.% (black line), 2.5 wt.% (red line),and 4 wt.% (blue line) asphaltene content. The data were collected after 4h of injection CO2 rich gas at 500 psig.

It can be inferred that faster relaxation times around 300 ms and 1500 ms may arise from surface
relaxation on the precipitated asphaltenes. This surface relaxation is expected to be at faster relaxation times(Prunelet et al., 2004) (Figure 8 and Figure 9). The CO2 exposure induced the asphaltene precipitation from

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Figure 8—T2 relaxation spectra for (a) model oil (toluene 70% and heptane 30%) with 2.5 wt.% crude N1C asphaltenes at ambient pressure (b) model oil without asphaltenes at ambient pressure (c) model oilwith 2.5 wt.% crude N1-C asphaltenes from 1 to 7h of CO2 pressure (500 psig) and (d) model oil withoutasphaltenes from 2 to 6 h of CO2 pressure (500 psig). Colder colors to warmer colors indicate time progression.

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the dissolved stage. After the CO2 gas pressure was reduced back to ambient pressure, the two additional
peaks disappeared again indicating that the precipitated asphaltenes are re-dissolved into the model oil.
Figure 9 shows that the amplitudes of the T2 relaxation spectrum that correspond to the precipitatedasphaltenes (signal below 3000 ms) are directly correlated to the initial asphaltene content in the model oil.

Figure 10—HP-DSC results for a water-in crude oil (N1-C) emulsion with 30%
water cut and 10 wt.% NaCl. Cycle 1 (red), cycle 2 (blue), cycle 3 (green).

High pressure rheological measurements of hydrate slurry flow
The relative viscosity profile as a fuction of time of gas hydrate slurries formed using 30 and 50 vol.% watercut emulsions of crude N1-C, and at 1000 psig and are shown in Figure 11. These tests were conducted at
5 and 10 wt.% salinity (NaCl). The tests conducted at 10 wt.% NaCl show only a small increase in relativeviscosity due to the small volume of hydrate formed; 2 vol.% of hydrate formed in the 30 vol.% water cut
test and 12 vol.% of hydrate formed in the 50 vol.% hydrate tests. On the other hand, there was a higher
increase in relative viscosity for the test conducted at 50 vol.% water and 5 wt.% NaCl. The higher increase
in relative viscosity was due to the higher amount of hydrate formed; 23 vol.% of hydrates formed in thisslurry. The lower amount of hydrates formed in the 10 wt.% NaCl tests was as expected due to lower hydrate
subcooling. The subcooling for 10 wt.% NaCl tests is ~9.2 °C, while the subcooling for 5 wt.% NaCl testis ~12.8 °C.

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Emulsion Stability with Hydrates. HP-DSC measurements
The thermogram of the HP-DSC investigation (heating path) for the 30 vol.% water content emulsion (crudeN1-C) with 10 wt.% of NaCl at 1000 psi of natural gas is shown in Figure 10. In this test, the agglomerated
hydrate particle will dissociate into larger water droplets compared to the initial water droplet. As such, inthe subsequent formation cycle, there will be less hydrate formation due to the lower total surface area ofwater droplets. Thus, the stability of the emulsion with hydrate formation/dissociation can be determinedby evaluating the amount of hydrate formed in each cycle. As can be seen in Figure, the intensity of hydratedissociation peak in the first cycle is larger compared to the intensity of the hydrate dissociation peak in thesecond and third cycles. This is an indication that there was significant hydrate agglomeration occurringin the system (Lachance, 2008).

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Additionally, the results show larger fluctuations in the viscosity profile for tests conducted at 5 wt.
% NaCl and 50 vol.% water content. From previous investigations, these fluctuations are the results offormation of severe hydrate deposits on the walls of the rheometer (Majid et al., 2019). In comparison, there
were no fluctuations in the tests conducted at 10 wt.% NaCl. The absence of fluctuations indicates that there
was a homogeneous distribution of hydrate particles in the slurries (Majid et al., 2019).
Next, measurements of yield stress of these hydrate slurries were also conducted (Figure 12). These tests
mimic the transient conditions of shut-in and restart, which is considered at the highest risk situation forfield operations. It should be noted that the yield stress was measured after the hydrate slurries were leftin shut-in conditions (no stirring) for 24 hours. A summary of the yield stress values obtained from thesemeasurements are presented in Table 4. The results indicate that higher amounts of hydrates will lead tohigher yield stress values. This agrees with previous studies (Rensing, 2010; Webb et al., 2012). At higher
particle concentration, the hydrate particles are more tightly packed. Thus, during the 24-hour shut-in time,
the hydrate particles would sinter, and this would lead to higher yield stress values.

Figure 12—Yield stress of hydrate slurries in crude oil N1-C formed from 30 and 50 vol.% watercontent emulsions at 200 RPM for tests formed using natural gas and (a) 10 wt.%, and (b) 5 wt.% NaCl.
Table 4—Yield stress (after shut-in/restart) of hydrate slurries in crude oil N1C formed at 1000 psig of natural gas at different water content and salinity
Water content (vol.%)

NaCl (wt.%)

Hydrate volume %Yield stress (Pa)

30

10

2

6

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Figure 11—Viscosity profiles of hydrate slurries in crude oil N1-C formed from 30 and 50 vol.
% water content emulsions at 200 RPM using the natural gas, a) 10 wt.% NaCl and, b) 5 wt.% NaCl.

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13

Water content (vol.%)

NaCl (wt.%)

Hydrate volume %Yield stress (Pa)

50

10

12

19

50

5

23

48

Figure 13—Viscosity profiles of hydrate slurries in crude oil N1-C formed from 50 vol.% watercontent, 5 wt.% salinity (NaCl) and CO2-rich natural gas composition. (a) Absolute viscosity,(b) relative viscosity (relative to oil phase) and (c) relative viscosity (relative to water phase).

Figures 13b and c show two different analyses of the viscosity profiles. In Figure 13b, relative viscosity
was determined with respect to oil as the continuous phase; while in Figure 13c, viscosity was determined
relative to water as the continuous phase. The relative viscosity with respect to water as the continuous
phase showed a significantly higher value. In this test, relative viscosity should be determined with respect
to the water phase due to phase inversion that had occurred. This would provide a better representation of
the effect of hydrate particles on the viscosity of the slurries.

Conclusions

Early detection of asphaltene precipitation and deposition and hydrate formation at field conditions is
critical for industry to minimize/optimize the application of mitigation/remediation strategies. In this work,
the asphaltene precipitation was determined using acoustic measurements and nuclear magnetic resonance(NMR). Asphaltene particles changed the velocity of the acoustic wave travelling through the sample.
Similar results were found for crude oil and model (toluene-heptane) systems. The magnitude of the acoustic

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Measurements of hydrate slurry viscosity were also conducted using 50 vol.% water, 5 wt.% NaCl andthe CO2-rich natural gas. Figure 13a shows the viscosity profile of the hydrate slurries as a function of time(pink). The viscosity profile of a similar test (50 vol.% water, 5 wt.% salinity) formed from the natural gas
composition (orange) is shown in the same plot for comparison. As can be seen in this plot, the viscosityof hydrate slurries formed from the CO2-rich natural gas composition was significantly lower compared to
the viscosity of hydrate slurries formed from the low-CO2 content gas (natural gas). The lower viscosity in
CO2-rich gas composition tests was due to a phase inversion that had occurred. This phase inversion was
indicated by the sharp and sudden decrease in the viscosity profile (at ~1.0 hr). It should be noted that inboth tests, the system began with crude oil as the continuous phase. However, in the test using the CO2rich gas, the formation of hydrate caused a phase inversion, whereby the system changed from being oil
continuous to water continuous. This phase inversion was confirmed by performing a dispersion test at theend of the rheometer experiment. It is hypothesized that the high CO2 content in the gas phase lowers thepH of the water. This lower water pH activated the natural hydrophilic surfactants in the oil, which thencaused the phase inversion (Poteau et al., 2005; Rodriguez-Abreu et al., 2006).

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OTC-31712-MS

Acknowledgements

The authors acknowledge Nippon Foundation - DeepStar® Partnership for providing funding and support
for this work through the project DeepStar® 20122. Champions of this project, Douglas Estanga(Chevron), Giovanny Grasso (ExxonMobil), Joe Lederhos (ExxonMobil), Daniel Crosby (Shell), Adriana
Teixeira (Petrobras), Leandro Valim (Petrobras), Nakano Yoshitaka (JX) and Ushiguchi Kento (JX) are
acknowledged for their technical support and advise.

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